Vol. 77 Thursday, No. 32 February 16, 2012

Part II

Environmental Protection Agency

40 CFR Parts 60 and 63 National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial- Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units; Final Rule

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ENVIRONMENTAL PROTECTION EPA–HQ–OAR–2011–0044 (NSPS B. Peer Review of the Hg Risk TSD AGENCY action) or Docket ID No. EPA–HQ– Supporting the Appropriate and OAR–2009–0234 (NESHAP action). All Necessary Finding for Coal and Oil-Fired 40 CFR Parts 60 and 63 documents in the dockets are listed on EGUs and EPA Response C. Summary of Results of Revised Hg Risk [EPA–HQ–OAR–2009–0234; EPA–HQ–OAR– the http://www.regulations.gov Web TSD of Risks to Populations With High 2011–0044, FRL–9611–4] site. Although listed in the index, some Levels of Self-Caught Fish Consumption information is not publicly available, D. Peer Review of the Approach for RIN 2060–AP52; RIN 2060–AR31 e.g., confidential business information Estimating Cancer Risks Associated With Cr and Ni Emissions in the U.S. EGU National Emission Standards for or other information whose disclosure is restricted by statute. Certain other Case Studies of Cancer and Non-Cancer Hazardous Air Pollutants From Coal- Inhalation Risks for Non-Mercury Hg and Oil-Fired Electric Utility Steam material, such as copyrighted material, is not placed on the Internet and will be HAP and EPA Response Generating Units and Standards of E. Summary of Results of Revised U.S. Performance for Fossil-Fuel-Fired publicly available only in hard copy EGU Case Studies of Cancer and Non- Electric Utility, Industrial-Commercial- form. Publicly available docket Cancer Inhalation Risks for Non-Mercury Institutional, and Small Industrial- materials are available either Hg HAP Commercial-Institutional Steam electronically through http:// F. Public Comments and Responses to the Appropriate and Necessary Finding Generating Units www.regulations.gov or in hard copy at EPA’s Docket Center, Public Reading G. EPA Affirms the Finding That It Is AGENCY: Environmental Protection Room, EPA West Building, Room 3334, Appropriate and Necessary To Regulate Agency (EPA). 1301 Constitution Avenue NW., EGUs To Address Public Health and Environmental Hazards Associated With ACTION: Final rule. Washington, DC 20004. This Docket Emissions of Hg and Non-Mercury Hg Facility is open from 8:30 a.m. to 4:30 HAP From EGUs SUMMARY: On May 3, 2011, under p.m., Monday through Friday, excluding IV. Denial of Delisting Petition authority of Clean Air Act (CAA) legal holidays. The telephone number A. Requirements of Section 112(c)(9) sections 111 and 112, the EPA proposed for the Public Reading Room is (202) B. Rationale for Denying UARG’s Delisting both national emission standards for 566–1744, and the telephone number for Petition hazardous air pollutants (NESHAP) the Air Docket is (202) 566–1741. C. EPA’s Technical Analyses for the Appropriate and Necessary Finding from coal- and oil-fired electric utility FOR FURTHER INFORMATION CONTACT: For steam generating units (EGUs) and Provide Further Support for the the NESHAP action: Mr. William Conclusion That Coal-Fired EGUs standards of performance for fossil-fuel- Maxwell, Energy Strategies Group, fired electric utility, industrial- Should Remain a Listed Source Category Sector Policies and Programs Division, V. Summary of the Final NESHAP commercial-institutional, and small (D243–01), Office of Air Quality A. What is the source category regulated by industrial-commercial-institutional Planning and Standards, U.S. this final rule? steam generating units (76 FR 24976). Environmental Protection Agency, B. What is the affected source? After consideration of public comments, Research Triangle Park, North Carolina C. What are the pollutants regulated by this the EPA is finalizing these rules in this 27711; Telephone number: (919) 541– final rule? D. What emission limits and work practice action. 5430; Fax number (919) 541–5450; Pursuant to CAA section 111, the EPA standards must I meet? Email address: [email protected]. E. What are the requirements during is revising standards of performance in For the NSPS action: Mr. Christian response to a voluntary remand of a periods of startup, shutdown, and Fellner, Energy Strategies Group, Sector malfunction? final rule. Specifically, we are amending Policies and Programs Division, (D243– F. What are the testing and initial new source performance standards 01), Office of Air Quality Planning and compliance requirements? (NSPS) after analysis of the public Standards, U.S. Environmental G. What are the continuous compliance comments we received. We are also Protection Agency, Research Triangle requirements? finalizing several minor amendments, Park, North Carolina 27711; Telephone H. What are the notification, recordkeeping and reporting requirements? technical clarifications, and corrections number: (919) 541–4003; Fax number to existing NSPS provisions for fossil I. Submission of Emissions Test Results to (919) 541–5450; Email address: the EPA fuel-fired EGUs and large and small [email protected]. industrial-commercial-institutional VI. Summary of Significant Changes Since Proposal steam generating units. SUPPLEMENTARY INFORMATION: The information presented in this A. Applicability Pursuant to CAA section 112, the EPA B. Subcategories is establishing NESHAP that will preamble is organized as follows: C. Emission Limits require coal- and oil-fired EGUs to meet I. General Information D. Work Practice Standards for Organic hazardous air pollutant (HAP) standards A. Does this action apply to me? HAP Emissions reflecting the application of the B. Where can I get a copy of this E. Requirements During Startup, maximum achievable control document? Shutdown, and Malfunction technology. This rule protects air C. Judicial Review F. Testing and Initial Compliance quality and promotes public health by D. What are the costs and benefits of these G. Continuous Compliance reducing emissions of the HAP listed in final rules? H. Emissions Averaging II. Background Information on the NESHAP I. Notification, Recordkeeping and CAA section 112(b)(1). A. What is the statutory authority for this Reporting DATES: This final rule is effective on final NESHAP? J. Technical/Editorial Corrections April 16, 2012. The incorporation by B. What is the litigation history of this final VII. Public Comments and Responses to the reference of certain publications listed rule? Proposed NESHAP in this rule is approved by the Director C. What is the relationship between this A. MACT Floor Analysis of the Federal Register as of April 16, final rule and other combustion rules? B. Rationale for Subcategories 2012. D. What are the health effects of pollutants C. Surrogacy emitted from coal- and oil-fired EGUs? D. Area Sources ADDRESSES: The EPA established two III. Appropriate and Necessary Finding E. Health-Based Emission Limits dockets for this action: Docket ID. No. A. Overview F. Compliance Date and Reliability Issues

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G. Cost and Technology Basis Issues A. Executive Order 12866, Regulatory Significantly Affect Energy Supply, H. Testing and Monitoring Planning and Review and Executive Distribution, or Use VIII. Background Information on the NSPS Order 13563, Improving Regulation and I. National Technology Transfer and A. What is the statutory authority for this Regulatory Review Advancement Act final NSPS? B. Paperwork Reduction Act J. Executive Order 12898: Federal Actions B. What is the regulatory authority for the C. Regulatory Flexibility Act as Amended To Address Environmental Justice in final rule? by the Small Business Regulatory Minority Populations and Low-Income IX. Summary of the Final NSPS Enforcement Fairness Act (RFA) of 1996 X. Summary of Significant Changes Since SBREFA), 5 U.S.C. 601 et seq. Populations Proposal D. Unfunded Mandates Reform Act of 1995 K. Congressional Review Act XI. Public Comments and Responses to the E. Executive Order 13132, Federalism Proposed NSPS F. Executive Order 13175, Consultation I. General Information XII. Impacts of the Final Rule and Coordination With Indian Tribal A. What are the air impacts? Governments A. Does this action apply to me? B. What are the energy impacts? G. Executive Order 13045, Protection of C. What are the cost impacts? Children From Environmental Health The regulated categories and entities D. What are the economic impacts? Risks and Safety Risks potentially affected by the final E. What are the benefits of this final rule? H. Executive Order 13211, Actions standards are shown in Table 1 of this XIII. Statutory and Executive Order Reviews Concerning Regulations That preamble.

TABLE 1—POTENTIALLY AFFECTED REGULATED CATEGORIES AND ENTITIES

1 Examples of potentially Category NAICS code regulated entities

Industry ...... 221112 Fossil fuel-fired electric utility steam generating units. Federal government ...... 2 221122 Fossil fuel-fired electric utility steam generating units owned by the fed- eral government. State/local/tribal government ...... 2 221122 Fossil fuel-fired electric utility steam generating units owned by states, tribes, or municipalities. 921150 Fossil fuel-fired electric utility steam generating units in Indian country. 1 North American Industry Classification System. 2 Federal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged.

This table is not intended to be C. Judicial Review General Counsel (Mail Code 2344A), exhaustive, but rather is meant to Environmental Protection Agency, 1200 provide a guide for readers regarding Under CAA section 307(b)(1), judicial Pennsylvania Ave. NW., Washington, entities likely to be affected by this review of this final rule is available only DC 20004. Note, under CAA section action. To determine whether you, as by filing a petition for review in the U.S. 307(b)(2), the requirements established Court of Appeals for the District of owner or operator of a facility, by this final rule may not be challenged Columbia Circuit by April 16, 2012. company, business, organization, etc., separately in any civil or criminal Under CAA section 307(d)(7)(B), only will be regulated by this action, you proceedings brought by EPA to enforce an objection to this final rule that was these requirements. should examine the applicability raised with reasonable specificity criteria in 40 CFR 60.40, 60.40Da, or during the period for public comment D. What are the costs and benefits of 60.40c or in 40 CFR 63.9981. If you have (including any public hearing) can be this final rule? any questions regarding the raised during judicial review. This Consistent with Executive Order (EO) applicability of this action to a section also provides a mechanism for 13563, ‘‘Improving Regulation and particular entity, consult either the air the EPA to convene a proceeding for Regulatory Review,’’ we have estimated permitting authority for the entity or reconsideration, ‘‘[i]f the person raising the costs and benefits of the final rule. your EPA regional representative as an objection can demonstrate to the This rule will reduce emissions of HAP, listed in 40 CFR 60.4 or 40 CFR 63.13 Administrator that it was impracticable including mercury (Hg), from the (General Provisions). to raise such objection within [the electric power industry. Installing the period for public comment] or if the technology necessary to reduce B. Where can I get a copy of this grounds for such objection arose after emissions directly regulated by this rule document? the period for public comment (but will also reduce the emissions of In addition to being available in the within the time specified for judicial directly emitted PM2.5 and sulfur dockets, an electronic copy of this review) and if such objection is of dioxide (SO2), a PM2.5 precursor. The action will also be available on the central relevance to the outcome of the benefits associated with these PM and Worldwide Web (WWW) through the rule[.]’’ Any person seeking to make SO2 reductions are referred to as co- such a demonstration to us should Technology Transfer Network (TTN). benefits, as these reductions are not the submit a Petition for Reconsideration to Following signature by the primary objective of this rule. the Office of the Administrator, The EPA estimates that this final rule Administrator, a copy of the action will Environmental Protection Agency, will yield annual monetized benefits (in be posted on the TTN’s policy and Room 3000, Ariel Rios Building, 1200 2007$) of between $37 to $90 billion guidance page for newly proposed or Pennsylvania Ave. NW., Washington, using a 3 percent discount rate and $33 promulgated rules at the following DC 20004, with a copy to the person to $81 billion using a 7 percent discount address: http://www.epa.gov/ttn/oarpg/. listed in the preceding FOR FURTHER rate. The great majority of the estimates The TTN provides information and INFORMATION CONTACT section, and the are attributable to co-benefits from technology exchange in various areas of Associate General Counsel for the Air reductions in PM2.5-related mortality. air pollution control. and Radiation Law Office, Office of The annual social costs, approximated

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by the sum of the compliance costs and of the benefits are associated with mortalities estimated to occur as a result monitoring and reporting costs, are $9.6 reducing PM2.5 levels at the low end of of this rule. The EPA could not billion (2007$) and the annual the concentration distributions monetize some costs and important quantified net benefits (the difference examined in the epidemiology studies benefits, such as some Hg benefits and between benefits and costs) are $27 to from which the PM2.5-mortality those for the HAP reduced by this final $80 billion using a 3 percent discount relationships used in this analysis are rule other than Hg. Upon considering rate or $24 to $71 billion using a 7 derived. these limitations and uncertainties, it percent discount rate. It is important to The benefits of this rule outweigh remains clear that the benefits of this note that the PM2.5 co-benefits reported costs by between 3 to 1 or 9 to 1 rule, referred to in short as the Mercury here contain uncertainty, due in part to depending on the benefit estimate and and Air Toxics Standards (MATS), are the important assumption that all fine discount rate used. The co-benefits are substantial and far outweigh the costs. particles are equally potent in causing substantially attributable to the 4,200 to premature mortality and because many 11,000 fewer PM2.5-related premature

TABLE 2—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE FINAL RULE IN 2016 [Billions of 2007$] a

3% Discount rate 7% Discount rate

Total Monetized Benefits b ...... $37 to $90 ...... $33 to $81. Partial Hg-related Benefits c ...... $0.004 to $0.006 ...... $0.0005 to $0.001. b PM2.5-related Co-benefits ...... $36 to $89 ...... $33 to $80. Climate-related Co-Benefits d ...... $0.36 ...... $0.36. Total Social Costs e ...... $9.6 ...... $9.6. Net Benefits ...... $27 to $80 ...... $24 to $71. Non-monetized Benefits ...... Visibility in Class I areas. Other neurological effects of Hg exposure. Other health effects of Hg exposure. Health effects of ozone and direct exposure to SO2 and NO2. Ecosystem effects. Health effects from commercial and non-freshwater fish consumption. Health risks from exposure to non-mercury HAP. a All estimates are for 2016, and are rounded to two significant figures. b The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5. The reduction in premature fatali- ties each year accounts for over 90 percent of total monetized benefits. Benefits in this table are nationwide and are associated with directly emitted PM2.5 and SO2 reductions. The estimate of social benefits also includes CO2-related benefits calculated using the social cost of carbon, discussed further in chapter 5 of the RIA. Mercury benefits were calculated using the baseline from proposal. The difference in emissions reduc- tions between proposal and final does not substantially affect the Hg benefits. c Based on an analysis of health effects due to recreational freshwater fish consumption. d This table shows monetized CO2 co-benefits that were calculated using the global average social cost of carbon estimate at a 3 percent dis- count rate. In section 5.6 of the Regulatory Impact Analysis (RIA) we also report the monetized CO2 co-benefits using discount rates of 5 per- cent, 2.5 percent, and 3 percent (95th percentile). e Total social costs are approximated by the compliance costs for both coal- and oil-fired units. This includes monitoring, recordkeeping, and reporting costs.

For more information on how EPA is proposal. The comments express United States (U.S.) with emissions of addressing EO 13563, see the EO concerns about the presence of Hg in the 29 tons per year, on a path to reducing discussion in the Statutory and environment and the effect it has on those emissions by approximately 90 Executive Order Reviews section of this human health, concerns about the costs percent. Emissions of other toxic metals, preamble. of the rule, how challenging it may be such as arsenic (As) and nickel (Ni), for some sources to comply and dioxins and furans, acid gases II. Background Information on the questions about the impact it may have (including hydrochloric acid (HCl) and NESHAP on this country’s electricity supply and SO2) will also decrease dramatically On May 3, 2011, the EPA proposed economy. Many comments provided with the installation of pollution this rule to address emissions of toxic additional information and data that controls. And the flexibilities air pollutants from coal and oil-fired have enriched the factual record and established in this rule along with other electric generating units as required by enabled EPA to finalize a rule that available tools provide a clear pathway the CAA. The proposal explained at fulfills the mandate of the CAA while to compliance without jeopardizing the length the statutory history and providing flexibility and compliance country’s energy supply. requirements leading to this rule, the options to affected sources—options This preamble explains EPA’s factual and legal basis for the rule and that make the rule less costly and appropriate and necessary finding, the its specific provisions, and the costs and compliance more readily manageable. elements of the final rule, key changes benefits to the public health and This rule establishes uniform the EPA is making in response to environment from the proposed emissions-control standards that sources comments submitted on the proposed requirements. can meet with proven and available rule, and our responses to many of the The EPA received over 900,000 technologies and operational processes comments we received. A full response comments from members of the public in a timeframe that is achievable. They to comments is provided in the response on the proposed rule, substantially more will put this industry, now the single to comments document available in the than for any other prior regulatory largest source of Hg emissions in the docket for this rulemaking.

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A. What is the statutory authority for than 30 sources. See CAA section to conduct the last required evaluation, this final rule? 112(d)(3)(A) and (B), respectively. This ‘‘a study to determine the threshold Congress established a specific level of minimum stringency is referred level of mercury exposure below which structure for determining whether to to as the ‘‘MACT floor,’’ and the EPA adverse human health effects are not regulate EGUs under CAA section 112.1 cannot consider cost in setting the floor. expected to occur’’ (NIEHS Study). See Specifically, Congress enacted CAA For new sources, MACT standards must CAA section 112(n)(1)(C). The NIEHS section 112(n)(1). be at least as stringent as the control was required to submit the results to Section 112(n)(1)(A) of the CAA level achieved in practice by the best Congress by November 15, 1993. Id. In requires the EPA to conduct a study to controlled similar source. See CAA conducting this study, NIEHS was to evaluate the remaining public health section 112(d)(3). determine ‘‘a threshold for mercury hazards that are reasonably anticipated The EPA also must consider more concentrations in the tissue of fish to occur as a result of EGUs’ HAP stringent ‘‘beyond-the-floor’’ control which may be consumed (including emissions after imposition of CAA options. When considering beyond-the- consumption by sensitive populations) requirements. The EPA must report the floor options, the EPA must consider the without adverse effects to public results of that study to Congress, and maximum degree of reduction in HAP health.’’ Id. regulate EGUs ‘‘if the Administrator emissions and take into account costs, In addition, Congress, in conference finds such regulation is appropriate and energy, and non-air quality health and report language associated with the necessary,’’ after considering the results environmental impacts when doing so. EPA’s fiscal year 1999 appropriations, of that study. Thus, CAA section See Cement Kiln Recycling Coal. v. EPA, directed the EPA to fund the National 112(n)(1)(A) governs how the 255 F.3d 855, 857–58 (D.C. Cir. 2001). Academy of Sciences (NAS) to perform Administrator decides whether to list Alternatively, the EPA may set a an independent evaluation of the EGUs for regulation under CAA section health-based standard for HAP that have available data related to the health 112. See New Jersey v. EPA, 517 F.3d an established health threshold, and the impacts of methylmercury (MeHg) (NAS 574 at 582 (D.C. Cir. 2008) (‘‘Section standard must provide ‘‘an ample Study or MeHg Study). H.R. Conf. Rep. 112(n)(1) governs how the margin of safety.’’ See CAA section No 105–769, at 281–282 (1998). Administrator decides whether to list 112(d)(4). As these standards could be Specifically, Congress required NAS to EGUs; it says nothing about delisting less stringent than MACT standards, the advise the EPA as to the appropriate EGUs.’’). Agency must have detailed information reference dose (RfD) for MeHg. 65 FR As directed, the EPA conducted the on HAP emissions from the subject 79826. The RfD is the amount of a study to evaluate the remaining public sources and sources located near the chemical which, when ingested daily health hazards and reported the results subject sources before exercising its over a lifetime, is anticipated to be to Congress (Utility Study Report to discretion to set such standards. without adverse health effects to Congress (Utility Study)).2 We discuss For area sources, the EPA may issue humans, including sensitive this study below in conjunction with standards or requirements that provide subpopulations. In the same conference other studies that CAA section 112(n)(1) for the use of generally available control report, Congress indicated that the EPA requires concerning EGUs. See also 76 technologies or management practices should not make the appropriate and FR 24982–24984 (summarizing studies). (GACT standards) in lieu of necessary regulatory determination for Once the EPA lists a source category promulgating MACT or health-based Hg emissions until the EPA had pursuant to CAA section 112(c), the standards. See CAA section 112(d)(5). reviewed the results of the NAS Study. As noted above, CAA section 112(n) EPA must then establish technology- See H.R. Conf. Rep. No 105–769, at 281– requires completion of various reports based emission standards under CAA 282 (1998). section 112(d). For major sources, the concerning EGUs. For the first report, As directed by Congress through the Utility Study, Congress required the EPA must establish emission standards different vehicles, the NAS Study and EPA to evaluate the hazards to public that ‘‘require the maximum degree of the NIEHS Study evaluated the same health reasonably anticipated to occur reduction in emissions of the hazardous issues. The NIEHS completed the as the result of HAP emissions from air pollutants subject to this section’’ NIEHS Study in 1995,3 and the NAS EGUs after imposition of the that the EPA determines are achievable completed the NAS Study in 2000.4 requirements of the CAA. See CAA taking into account certain statutory Because NAS completed its study 5 section 112(n)(1)(A). The EPA was factors. See CAA section 112(d)(2). years after the NIEHS Study, and required to report results from this These standards are referred to as considered additional information not study to Congress by November 15, ‘‘maximum achievable control earlier available to NIEHS, for purposes 1993. Id. Congress also directed the EPA of this document we discuss the content technology’’ or ‘‘MACT’’ standards. The to conduct ‘‘a study of mercury of the NAS Study as opposed to the MACT standards for existing sources emissions from [EGUs], municipal waste NIEHS Study. must be at least as stringent as the combustion units, and other sources, The EPA conducted the studies average emission limitation achieved by including area sources’’ (Mercury required by CAA section 112(n)(1) the best performing 12 percent of Study). See CAA section 112(n)(1)(B). concerning utility HAP emissions, the existing sources in the category (for The EPA was required to report the Utility Study and the Mercury Study,5 which the Administrator has emissions results from this study to Congress by and completed both by 1998. Prior to information) or the best performing 5 November 15, 1994. Id. In conducting issuance of the Mercury Study, the EPA sources for source categories with less this Mercury Study, Congress directed the EPA to ‘‘consider the rate and mass 1 ‘‘Electric utility steam generating unit’’ is 3 NIEHS Study, August 1995; EPA–HQ–OAR– defined, in part, as any ‘‘fossil fuel fired combustion of such emissions, the health and 2009–3053. unit of more than 25 megawatts that serves a environmental effects of such emissions, 4 National Research Council (NAS). 2000. generator that produces electricity for sale.’’ See technologies which are available to Toxicological Effects of Methylmercury. Committee CAA section 112(a)(8). control such emissions, and the costs of on the Toxicological Effects of Methylmercury, 2 U.S. EPA. Study of Hazardous Air Pollutant Board on Environmental Studies and Toxicology, Emissions from Electric Utility Steam Generating such technologies.’’ Id. Congress National Research Council. Units—Final Report to Congress. EPA–453/R–98– directed the National Institute of 5 Mercury Study Report to Congress, December 004a. February 1998. Environmental Health Sciences (NIEHS) 1997; EPA–HQ–OAR–2009–0234–3054.

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engaged in two extensive external peer On February 8, 2008, the D.C. Circuit CAA section 112(c). The EPA settled reviews of the document. vacated both the 2005 Action and that litigation. The consent decree On December 20, 2000, the EPA CAMR. The D.C. Circuit held that the resolving the case requires the EPA to issued a finding pursuant to CAA EPA failed to comply with the sign a notice of proposed rulemaking section 112(n)(1)(A) that it was requirements of CAA section 112(c)(9) setting forth the EPA’s proposed CAA appropriate and necessary to regulate for delisting source categories. section 112(d) emission standards for coal- and oil-fired EGUs under CAA Specifically, the D.C. Circuit held that coal- and oil-fired EGUs by March 16, section 112 and added such units to the CAA section 112(c)(9) applies to the 2011, and a notice of final rulemaking list of source categories subject to removal of ‘‘any source category’’ from by December 16, 2011.8 regulation under CAA section 112(d). In the CAA section 112(c) list, including C. What is the relationship between this making that finding, the EPA considered EGUs. The D.C. Circuit found that, by final rule and other combustion rules? the Utility Study, the Mercury Study, enacting CAA section 112(c)(9), the NAS Study, and certain additional Congress limited the EPA’s discretion to 1. CAA Section 111 information, including information reverse itself and remove source about Hg emissions from coal-fired The EPA promulgated revised NSPS categories from the CAA section 112(c) for SO , nitrogen oxides (NO ), and PM EGUs that the EPA obtained pursuant to list. The D.C. Circuit found that the 2 X an information collection request (ICR) under CAA section 111 for EGUs (40 EPA’s contrary position would ‘‘nullify CFR part 60, subpart Da) and industrial under the authority of CAA section 114. § 112(c)(9) altogether.’’ New Jersey v. 65 FR 79826–27. boilers (IB) (40 CFR part 60, subparts Db EPA, 517 F.3d 574, 583 (D.C. Cir. 2008). and Dc) on February 27, 2006 (71 FR B. What is the litigation history of this The D.C. Circuit did not reach the 9866). As noted elsewhere, in this final rule? merits of petitioners’ arguments on action we are finalizing certain CAMR, but vacated CAMR for existing Shortly after issuance of the December amendments to 40 CFR part 60, subpart sources because coal-fired EGUs were 2000 finding, an industry group Da. In developing this final rule, we already listed sources under CAA challenged that finding in the Court of considered the monitoring, testing, and section 112. The D.C. Circuit reasoned Appeals for the D.C. Circuit (D.C. recordkeeping requirements of the that even under the EPA’s own Circuit). Utility Air Regulatory Group existing and revised NSPS to avoid interpretation of the CAA, regulation of (UARG) v. EPA, 2001 WL 936363, No. duplicating requirements to the extent existing sources’ Hg emissions under 01–1074 (D.C. Cir. July 26, 2001). The possible. CAA section 111 was prohibited if those D.C. Circuit dismissed the lawsuit sources were a listed source category 2. CAA Section 112 holding that it did not have jurisdiction under CAA section 112.6 because CAA section 112(e)(4) provides, Id. The D.C. The EPA has previously developed in pertinent part, that ‘‘no action of the Circuit vacated and remanded CAMR other non-EGU combustion-related Administrator * * * listing a source for new sources because it concluded NESHAP under CAA section 112(d). category or subcategory under that the assumptions the EPA made The EPA promulgated final NESHAP for subsection (c) of this section shall be a when issuing CAMR for new sources major source industrial, commercial and final agency action subject to judicial were no longer accurate (i.e., that there institutional boilers and process heaters review, except that any such action may would be no CAA section 112 regulation (IB) and area source industrial, be reviewed under section 7607 of (the of EGUs and that the CAA section 111 commercial and institutional boilers on CAA) when the Administrator issues standards would be accompanied by March 21, 2011 (40 CFR part 63, subpart emission standards for such pollutant or standards for existing sources). Id. at DDDDD, 76 FR 15608; and subpart JJJJJJ, category.’’ Id. (emphasis added). 583–84. Thus, CAMR and the 2005 76 FR 15249, respectively), and Pursuant to a settlement agreement, Action became null and void. promulgated standards for stationary the deadline for issuing emission On December 18, 2008, several combustion turbines (CT) on March 5, standards was March 15, 2005. environmental and public health 2004 (40 CFR part 63 subpart YYYY; 69 However, instead of issuing emission organizations filed a complaint in the FR 10512). In addition to these three standards pursuant to CAA section U.S. District Court for the District of NESHAP, on March 21, 2011, the EPA 7 112(d), on March 29, 2005, the EPA Columbia. They alleged that the also promulgated final CAA section 129 issued the Section 112(n) Revision Rule Agency had failed to perform a standards for commercial and (2005 Action). That action delisted nondiscretionary duty under CAA institutional solid waste incineration EGUs after finding that it was neither section 304(a)(2), by failing to (CISWI) units, including energy appropriate nor necessary to regulate promulgate final CAA section 112(d) recovery units (40 CFR part 60, subparts such units under CAA section 112. In standards for HAP from coal- and oil- CCCC (NSPS) and DDDD (emission addition, on May 18, 2005, the EPA fired EGUs by the statutorily-mandated guidelines); 76 FR 15704); and a issued the Clean Air Mercury Rule deadline, December 20, 2002, 2 years definition of non-hazardous secondary (CAMR). 70 FR 28606. That rule after such sources were listed under materials that are solid waste (Non- established standards of performance for hazardous Solid Waste Definition Rule 6 emissions of Hg from new and existing In CAMR and the 2005 Action, EPA interpreted section 111(d) of the Act as prohibiting the Agency (40 CFR part 241, subpart B; 76 FR coal-fired EGUs pursuant to CAA from establishing an existing source standard of 15456)). Electric generating units and IB section 111. performance under CAA section 111(d) for any HAP Environmental groups, states, and emitted from a particular source category, if the 8 The consent decree originally required EPA to tribes challenged the 2005 Action and source category is regulated under CAA section 112. sign a notice of final rulemaking no later than 7 American Nurses Association, Chesapeake Bay November 16, 2011; however, on October 21, 2011, CAMR. Among other things, the Foundation, Inc., Conservation Law Foundation, pursuant to paragraph 6 of the consent decree, the environmental and state petitioners Environment America, Environmental Defense parties agreed to a 30-day extension of the final rule argued that the EPA could not remove Fund, Izaak Walton League of America, Natural deadline. As stated in the stipulation memorializing EGUs from the CAA section 112(c) Resources Council of Maine, Natural Resources the extension, the parties agreed to the extension of Defense Council, Physicians for Social 30 days because EPA provided an additional 30 source category list without following Responsibility, Sierra Club, The Ohio days for public comment and the time was the requirements of CAA section Environmental Council, and Waterkeeper Alliance, necessary to respond to comments submitted on the 112(c)(9). Inc. (Civ. No. 1:08–cv–02198 (RMC)). proposed rule.

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that combust fossil fuel and solid waste, we do not consider these CTs to be Units that do not meet the EGU as that term is defined by the EGUs for purposes of this final rule.9 definition will in most cases be Administrator pursuant to the Resource The December 2000 listing discussed considered IB units subject to one of the Conservation and Recovery Act (RCRA), above did not list natural gas-fired two Boiler NESHAP. Thus, for example, see 76 FR 15456, will be subject to EGUs. Thus, this final rule does not a biomass-fired EGU, regardless of size, standards issued pursuant to CAA regulate a unit that otherwise meets the that utilizes fossil fuels for startup and section 129 (e.g., CISWI), unless they CAA section 112(a)(8) definition of an flame stabilization purposes only (i.e., meet one of the exemptions in CAA EGU but that combusts natural gas less than or equal to 10.0 percent of the section 129(g)(1). Clean Air Act section exclusively or natural gas in average annual heat input in any 3 129 standards are discussed in more combination with another fossil fuel consecutive calendar years or less than detail below. where the natural gas constitutes 90.0 or equal to 15.0 percent of the annual heat input during any one calendar The two IB (Boiler) NESHAP, the CT percent or more of the average annual year) is not considered to be a fossil NESHAP, and this final rule will heat input during any 3 consecutive fuel-fired EGU under this final rule. regulate HAP emissions from sources calendar years or 85.0 percent or more A cogeneration facility that sells that combust fossil fuels for electrical of the annual heat input in one calendar electricity to any utility power power, process operations, or heating. year. We consider such units to be distribution system equal to more than The differences among these rules are natural gas-fired EGUs notwithstanding one-third of its potential electric output due to the size of the units (megawatt the combustion of some coal or oil (or capacity and more than 25 MW will be (MW), megawatt-electric (MWe), or derivative thereof) and such units are considered an EGU if the facility is British thermal unit per hour (Btu/hr)), not subject to this final rule. fossil fuel-fired as that term is defined the boiler/furnace technology, and/or The CAA does not define the terms in the final rule. the portion of their electrical output (if ‘‘fossil fuel-fired’’ and ‘‘fossil fuel.’’ In We recognize that different CAA any) for sale to any utility power this rule, we are finalizing definitions section 112 rules may impact a distribution systems. for both terms for purposes of this rule. The definition of ‘‘fossil fuel-fired’’ will particular unit at different times. For Pursuant to the CAA, an EGU is ‘‘any help determine the applicability of the example, the Boiler NESHAP may cover fossil fuel fired combustion unit of more final rule to combustion units that sell some cogeneration units. Such a unit than 25 megawatts that serves a electricity to the utility power may decide to increase or decrease the generator that produces electricity for distribution system. The definition of proportion of production output it sale. A unit that cogenerates steam and ‘‘fossil fuel-fired’’ establishes the supplies to the electric utility grid, thus electricity and supplies more than one- amount of fossil fuel combustion causing the unit to meet the EGU third of its potential electric output necessary to make a unit ‘‘fossil fuel- cogeneration criteria (i.e., greater than capacity and more than 25 megawatts fired’’ and hence potentially subject to one-third of its potential output capacity electrical output to any utility power this final rule. These definitions will and greater than 25 MW). A unit subject distribution system for sale shall be help determine applicability of the final to one of the Boiler NESHAP that considered an electric utility steam rule to units that primarily fire non- increases its electricity output and generating unit.’’ CAA section 112(a)(8). fossil fuels (e.g., biomass) but generally meets the definition of an EGU would We consider all of the MW ratings start up using either natural gas or be subject to the final EGU NESHAP. quoted in the final rule to be the original distillate oil and may use these fuels (or Another rule intersection may occur rated nameplate capacity of the unit. We coal) during normal operation for flame where one or more coal- or oil-fired consider cogeneration to be the stabilization. EGU(s) share an air pollution control simultaneous production of power In addition, the EPA is finalizing in device (APCD) and/or an exhaust stack (electricity) and another form of useful the definition of ‘‘fossil fuel-fired’’ that, with one or more similarly-fueled IB thermal energy (usually steam or hot among other things, an EGU must fire unit(s). To demonstrate compliance water) from a single fuel-consuming coal or oil for more than 10.0 percent of with two different rules, either the process. the average annual heat input during emissions would need to be apportioned We consider any combustion unit, any 3 consecutive calendar years or for to the appropriate source or the more regardless of size, that produces steam more than 15.0 percent of the annual stringent emission limit would need to to serve a generator that produces heat input during any one calendar year be met. Data needed to apportion electricity exclusively for industrial, after the applicable compliance date in emissions are not currently required by commercial, or institutional purposes order to be considered a fossil fuel-fired this final rule or the final boiler (i.e., makes no sales to the national EGU subject to this final rule. The EPA NESHAP and are not otherwise electrical distribution grid) to be an IB has based these threshold percentage available. Therefore, the EPA is unit. We do not consider a fossil fuel- values on the definition of ‘‘oil-fired’’ in finalizing the requirement to comply fired combustion unit that serves a the Acid Rain Program (ARP) found at with the more stringent emission limit. generator that produces electricity for 40 CFR 72.2. Though the EPA does not 3. CAA Section 129 sale to be an EGU under the final rule have annual heat input data for, for if the size of the combustion unit is less example, biomass co-fired EGUs Clean Air Act section 129 regulates than or equal to 25 MW. Units that are because their use is not yet units that combust ‘‘non-hazardous 25 MW or less are likely subject to one commonplace, we believe this secondary materials,’’ as that term is of the two Boiler NESHAP. definition accounts for the use of fossil defined by the Administrator under the Resource Conservation and Recovery Because of the combustion technology fuels for flame stabilization use without inappropriately subjecting such units to Act (RCRA), that are ‘‘solid wastes.’’ On of simple-cycle and combined-cycle this final rule. March 21, 2011, the EPA promulgated stationary CTs (with the exception of the final Non-Hazardous Solid Waste integrated gasification combined cycle 9 Definition Rule (76 FR 15456). Any EGU (IGCC) units that burn gasified coal or The CT NESHAP regulates HAP emissions from all simple-cycle and combined-cycle stationary CTs that combusts any solid waste as petroleum coke synthesis gas/syngas), producing electricity or steam for any purpose. defined in that final rule is a solid waste

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incineration unit subject to emissions far the largest anthropogenic source of CAA section 112 is intended to address standards under CAA section 129. Hg in the U.S. In addition, EGUs are the HAP emissions. See 76 FR 24984–20985 In the Non-Hazardous Solid Waste largest source of HCl, hydrogen fluoride (for further discussion of 2000 finding). Definition Rule, the EPA determined (HF), and selenium (Se) emissions, and Because several years had passed that coal refuse from current mining a major source of metallic HAP since the 2000 finding, the EPA operations is not considered to be a emissions including As, chromium (Cr), performed additional technical analyses ‘‘solid waste’’ if it is not discarded. Coal Ni, and others. The discrepancy is even for the proposed rule, even though those refuse that is in legacy coal refuse piles greater now that almost all other major analyses were not required. These is considered a ‘‘solid waste’’ because it source categories have been required to analyses included a national-scale Hg has been discarded. However, if control Hg and other HAP under CAA risk assessment focused on populations discarded coal refuse is processed in the section 112. In 2005, U.S. EGUs emitted with high levels of self-caught fish same manner as currently mined coal 50 percent of total domestic consumption, and a set of 16 case refuse, the coal refuse would not be anthropogenic Hg emissions, 62 percent studies of inhalation cancer risks for considered a solid waste but instead of total As emissions, 39 percent of total non-Hg HAP. The analyses confirm that would be considered a product fossil cadmium (Cd) emissions, 22 percent of it remains appropriate and necessary to fuel. Therefore, the combustion of such total Cr emissions, 82 percent of total regulate U.S. EGUs under section 112. material by a combustion unit would HCl emissions, 62 percent of total HF In the preamble to the proposed rule, not subject that unit to regulation under emissions, 28 percent of total Ni the EPA reported the results of those CAA section 129. Instead, the unit emissions, and 83 percent of total Se additional technical analyses. Those would be subject to this final rule if it emissions.10 Exposure to these HAP, analyses confirmed the 2000 finding meets the definition of EGU. In the depending on exposure duration and that it is appropriate to regulate U.S. proposed rule, we assumed that all units levels of exposures, is associated with a EGUs under section 112 by that combust coal refuse and otherwise variety of adverse health effects. These demonstrating that (1) Hg continues to meet the definition of a coal-fired EGU adverse health effects may include pose a hazard to public health because are in fact combusting newly mined coal chronic health disorders (e.g., irritation up to 28 percent of watersheds were refuse or coal refuse from legacy piles of the lung, skin, and mucus estimated to have Hg deposition that has been processed such that it is membranes; detrimental effects on the attributable to U.S. EGUs that not a solid waste. We did not receive central nervous system; damage to the contributes to potential exposures above any information since proposal that kidneys; and alimentary effects such as the reference dose for methylmercury would cause us to revise this nausea and vomiting). Two of the HAP (MeHg RfD), a level above which there determination in the final rule. are classified as human carcinogens (As is increased risk of neurological effects Further, CAA section 129(g)(1)(B) and CrVI) and two as probable human in children, (2) non-Hg HAP emissions exempts from regulation carcinogens (Cd and Ni). See 76 FR pose a hazard to public health because 25003–25005 for a fuller discussion of case studies at 16 facilities ‘‘* * * qualifying small power production the health effects associated with these demonstrated that lifetime cancer risks facilities, as defined in section 796(17)(C) of at 4 of the facilities exceed 1 in 1 Title 16, or qualifying cogeneration facilities, pollutants. million, and (3) U.S. EGUs remain the as defined in section 796(18)(B) of Title 16, III. Appropriate and Necessary Finding which burn homogeneous waste * * * for largest domestic source of Hg emissions the production of electric energy or in the A. Overview and several HAP (e.g., HF, Se, HCl), and are among the largest contributors for case of qualifying cogeneration facilities In December 2000, the EPA issued a which burn homogeneous waste for the other HAP (e.g., As, Cr, Ni, HCN). Thus, finding pursuant to CAA section production of electric energy and steam or in the preamble to the proposed rule, 112(n)(1)(A) that it was appropriate and forms of useful energy (such as heat) which the EPA found that Hg and non-Hg HAP necessary to regulate coal- and oil-fired are used for industrial, commercial, heating emissions from U.S. EGUs pose hazards EGUs under CAA section 112 and added or cooling purposes * * *’’ to public health, which confirmed the such units to the list of source categories If the ‘‘homogeneous waste’’ material 2000 finding and demonstrated that it subject to regulation under section that such facilities combust is also a remains appropriate to regulate U.S. 112(d). The EPA found that it was fossil fuel, and those facilities otherwise EGUs under section 112. appropriate to regulate HAP emissions meet the definition of an EGU under In the preamble to the proposed rule, from coal- and oil-fired EGUs because, CAA section 112(a)(8), then those the EPA also found that it is appropriate among other reasons, Hg is a hazard to facilities are exempt from regulation to regulate U.S. EGUs because (1) Hg public health, and U.S. EGUs are the emissions pose a hazard to the under CAA section 129 but covered largest domestic source of Hg emissions. environment and wildlife, adversely under this final rule. For example, a The EPA also found it appropriate to impacting species of fish-eating birds qualifying small power production regulate HAP emissions from EGUs and mammals, (2) acid gas HAP pose a facility or cogeneration facility because it had identified certain control hazard to the environment because they combusting only coal refuse that is a options that would effectively reduce contribute to aquatic acidification, and solid waste and a ‘‘homogenous waste,’’ HAP emissions from U.S. EGUs. The (3) effective controls are available to as that term is defined in the final CAA EPA found that it was necessary to reduce Hg and non-Hg HAP emissions section 129 CISWI standards, would be regulate HAP emissions from U.S. EGUs from U.S. EGUs. subject to this final rule if the unit also under section 112 because the The additional analyses reported in met the definition of EGU. implementation of other requirements the preamble to the proposed rule also under the CAA will not adequately D. What are the health effects of confirmed that it remains necessary to address the serious public health and pollutants emitted from coal- and oil- regulate U.S. EGU under CAA section environmental hazards arising from fired EGUs? 112. These analyses demonstrated that HAP emissions from U.S. EGUs and that This final rule protects air quality and (1) Hg emissions from U.S. EGUs promotes public health by reducing remaining in 2016 are reasonably 10 From 2005 National-Scale Air Toxics emissions of some of the HAP listed in Assessment (NATA), available at http:// anticipated to pose a hazard to public CAA section 112(b)(1). Utilities are by www.epa.gov/ttn/atw/nata2005/. health after imposition of other CAA

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requirements, such as the Cross-State the peer review, the revised results CAA section 112. We also conclude that Air Pollution Rule (CSAPR); (2) U.S. show that up to 29 percent of modeled it remains appropriate to regulate U.S. EGUs are reasonably anticipated to watersheds are estimated to have Hg EGUs under CAA section 112 because of remain the largest source of Hg in the deposition attributable to U.S. EGUs the magnitude of Hg and non-Hg U.S. and thus contribute to the risk that contributes to potential exposures emissions, environmental effects of Hg associated with exposure to MeHg; (3) above the MeHg RfD, an increase of one and certain non-Hg emissions, and the Hg emissions from U.S. EGUs after percentage point from the results availability of controls to reduce HAP imposition of the requirements of the reported in the proposed rule. We emissions from EGUs. CAA were projected to be 29 tons per conclude that Hg emissions from EGUs In addition, we conclude that the year in 2016, similar to levels of Hg pose a hazard to public health based on emitted today, indicating that further the total of 29 percent of modeled hazards to public health from Hg and substantial reductions in Hg emissions watersheds at risk. Our analyses show non-Hg emissions from U.S. EGUs are are not reasonably anticipated without that of the 29 percent of watersheds reasonably anticipated to remain after federal regulations on Hg from U.S. with population at-risk, in 10 percent of imposition of the requirements of the EGUs; (4) we cannot be certain that the those watersheds U.S. EGU deposition CAA. The same is true for hazards to the identified cancer risks attributable to alone without considering deposition environment. Thus, we confirm that it is non-Hg emissions from U.S. EGUs will from other sources would lead to necessary to regulate U.S. EGUs under be addressed through imposition of the potential exposures that exceed the CAA section 112. MeHg RfD, and in 24 percent of those requirements of the CAA because B. Peer Review of the Hg Risk TSD watersheds, total potential exposures to companies can use compliance Supporting the Appropriate and strategies for criteria pollutants that do MeHg exceed the RfD and U.S. EGUs contribute at least 5 percent to Hg Necessary Finding for Coal and Oil- not achieve HAP co-benefits (e.g., Fired EGUs and EPA Response purchasing allowances in a trading deposition.14 15 Each of these results program); and (5) we cannot ensure that independently supports our conclusion In the preamble to the proposed rule, Hg and non-Hg HAP emissions that Hg emissions from EGUs pose the EPA stated that ‘‘in making the reductions achieved since 2005 would hazards to public health. finding that it remains appropriate and The peer review of the approach to be permanent without federally binding necessary to regulate EGUs to address estimate Ni and Cr cancer risk in the regulations for Hg from U.S. EGUs. public health and environmental Since issuance of the proposed rule, case studies also supported EPA’s assessment. The EPA enhanced this hazards associated with emissions of Hg the EPA has conducted peer reviews of and Non-Hg HAP from EGUs, the EPA the national-scale Hg risk assessment analysis in response to the peer review and public comments. The results of determined that the Hg Risk TSD (Hg Risk TSD) and the approach for supporting EPA’s 2011 review of U.S. estimating chromium and nickel those revised analyses show that 6 of 16 modeled facilities have lifetime cancer EGU health impacts should be peer- inhalation cancer risk in the case reviewed.’’ 16 We also indicated that due 11 12 risks greater than 1 in a million, thus studies. The peer review of the Hg to the court-ordered schedule for the Risk TSD was conducted by EPA’s confirming that non-Hg HAP emissions from U.S. EGUs remain a hazard to final rule, we planned to conduct the independent Science Advisory Board peer review as expeditiously as possible (SAB). The SAB stated that it ‘‘supports public health. Given Congress’ after issuance of the proposed rule, and the overall design of and approach to determination that categories of sources that the results of the peer review and the risk assessment and finds that it that emit HAP resulting in a lifetime any EPA response would be published should provide an objective, reasonable, cancer risk greater than 1 in a million before the final rule. Due to the and credible determination of the should not be removed from the CAA extension of the public comment period potential for a public health hazard from section 112(c) source category list and mercury emitted from U.S. EGUs.’’ 13 should continue to be regulated under and the volume of public comments SAB recommended several CAA section 112, the EPA concludes received on the analyses supporting the improvements to the data, methods and that risk above that level represents a proposed rule, we were unable to documentation of the analyses, which hazard to public health. publish EPA’s response prior to Based on our consideration of the EPA has fully addressed in the revised signature of the final rule. peer reviews, public comments, and our Hg Risk TSD. The EPA’s response to the peer review updated analyses, we confirm the As described in the revised Hg Risk the Hg Risk TSD is fully documented in findings that Hg and non-Hg HAP TSD, after addressing comments from emissions from U.S. EGUs pose hazards the revised Technical Support to public health and that it remains Document (TSD): National-Scale 11 U.S. EPA. 2011a. National-Scale Assessment of appropriate to regulate U.S. EGUs under Assessment of Hg Risk to Populations of Mercury Risk to Populations with High High Consumption of Self-Caught Fish Consumption of Self-caught Freshwater Fish In Support of the Appropriate and Necessary Finding 14 Because some watersheds with exposures In Support of the Appropriate and for Coal- and Oil-Fired Electric Generating Units. sufficient to exceed the RfD with Hg deposition Necessary Finding for Coal and Oil- Office of Air Quality Planning and Standards. from U.S. EGUs alone without considering Fired Electric Generating Units.17 The November. EPA–452/R–11–009. deposition from other sources also have U.S. EGU following sections describe the peer 12 U.S. EPA. 2011b. Supplement to Non-mercury contributions of more than 5 percent of total Hg Case Study Chronic Inhalation Risk Assessment for deposition, there is some overlap between the two review process that we followed, the Utility MACT Appropriate and Necessary risk metrics. This explains why the total percent of provide the peer review charge Analysis. Office of Air Quality Planning and watersheds exceeding either risk metric is less than questions presented to the peer review Standards. November. the sum of the individual risk metrics. panel, summarize the key 13 U.S. Environmental Protection Agency-Science 15 Requiring at least a 5 percent EGU contribution Advisory Board (U.S. EPA–SAB). 2011. Peer Review is a conservative approach given the increasing recommendations from the peer review, of EPA’s Draft National-Scale Mercury Risk risks associated with incremental exposures above and summarize our responses to those Assessment. EPA–SAB–11–017. September. the RfD. Because we are finding 24 percent of recommendations. Available on the Internet at http://yosemite.epa.gov/ watersheds with populations potentially at risk sab/sabproduct.nsf/ even using this conservative approach, we have BCA23C5B7917F5BF8525791A0072CCA1/$File/ confidence that emissions of Hg from U.S. EGUs are 16 76 FR 25012. EPA-SAB-11-017-unsigned.pdf. causing a hazard to public health. 17 U.S. EPA, 2011a.

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1. Summary of Peer Review Process the draft report at a public for additional detail on the benchmark Peer review is consistent with EPA’s teleconference on July 12, 2011, during used for interpreting the IQ loss open and transparent process to ensure which additional opportunities for estimates)? 22 that the Agency’s scientific assessments public comment were provided, and Question 4: Please comment on the and rulemakings are based on the best submitted a revised draft for quality spatial scale used in defining science available. This regulatory action review by the Chartered SAB before the watersheds that formed the basis for risk was supported by the Hg Risk TSD, end of the public comment period on estimates generated for the analysis (i.e., which is a highly influential scientific the rule. The Chartered SAB held a use of 12-digit hydrologic unit code assessment. Therefore, the EPA public teleconference on September 7, classification). To what extent do conducted a peer review in accordance 2011, to conduct a quality review of the [Hydrologic Unit Code] HUC12 with OMB’s Final Information Quality draft report; this teleconference also watersheds capture the appropriate Bulletin for Peer Review 18 as described included a final opportunity for public level of spatial resolution in the 23 below. All the materials related to the comment. The SAB submitted its final relationship between changes in 24 peer review, including the SAB’s final report to EPA on September 29, 2011. mercury deposition and changes in report, can be found in the docket for Notice of all the meetings was published MeHg fish tissue levels? (see section 1.3 this rulemaking. in the Federal Register and all of the and Appendix A of the Mercury Risk The EPA commissioned the peer materials discussed at the SAB TSD for additional detail on specifying review through EPA’s SAB, which meetings, including technical the spatial scale of watersheds used in provides independent advice and peer documents, presentations, meeting the analysis). review to EPA’s Administrator on the minutes, and draft reports were posted Question 5: Please comment on the scientific and technical aspects of for public access on the SAB Web site 25 extent to which the fish tissue data used environmental issues. The SAB and were added to the docket for the as the basis for the risk assessment are convened a 22-member peer review final rule on October 14, 2011. appropriate and sufficient given the goals of the analysis. Please comment on committee. The SAB process for 2. Peer Review Charge Questions selecting the panel began with two the extent to which focusing on data Federal Register Notices requesting The EPA asked the SAB to comment from the period after 1999 increases nominations for the Mercury Review on the Hg Risk TSD, including the confidence that the fish tissue data used Panel.19 Based on nominations received, overall design and approach and the use are more likely to reflect more a list of potential panel members, along of specific models and key assumptions. contemporaneous patterns of Hg with bio-sketches, was posted for public The EPA also asked the SAB to deposition and less likely to reflect comment on the SAB Web site on April comment on the extent to which earlier patterns of Hg deposition. Are 15, 2011. The members of the Mercury specific facets of the assessment were there any additional sources of fish Review Panel were announced on May well characterized in the Hg Risk TSD. tissue MeHg data that would be 24, 2011. The membership of the panel The specific charge questions are listed appropriate for inclusion in the risk below: included representatives of 16 academic assessment? Question 1. Please comment on the Question 6: Given the stated goal of institutions, 4 state health or scientific credibility of the overall estimating potential risks to highly environmental agencies, 1 federal design of the mercury risk assessment as exposed populations, please comment agency, and 1 utility industry 20 an approach to characterize human on the use of the 75th percentile fish organization. The panel held a public health exposure and risk associated tissue MeHg value (reflecting targeting meeting in Research Triangle Park, NC, with U.S. EGU mercury emissions (with of larger but not the largest fish for on June 15–17, 2011, which included a focus on those more highly exposed). subsistence consumption) as the basis the opportunity for public comment on Question 2. Are there any additional for estimating risk at each watershed. the Hg Risk TSD and the peer review critical health endpoint(s) besides IQ 21 Are there scientifically credible process. At the June 15–17 public loss, which could be quantitatively alternatives to use of the 75th percentile meeting, the panel completed a draft estimated with a reasonable degree of in representing potential population peer review report. The minutes of that confidence to supplement the mercury exposures at the watershed level? meeting and the draft peer review report risk assessment (see section 1.2 of the Question 7: Please comment on the were posted to the SAB public Web site Mercury Risk TSD for an overview of extent to which characterization of within the public comment period for the risk metrics used in the risk consumption rates and the potential the proposed rule. The panel discussed assessment)? location for fishing activity for high-end Question 3. Please comment on the self-caught fish consuming populations 18 Office of Management and Budget (OMB). 2004. benchmark used for identifying a modeled in the analysis are supported Final Information Quality Bulletin for Peer Review. potentially significant public health December. Available on the Internet at http:// by the available study data cited in the www.whitehouse.gov/omb/ impact in the context of interpreting the Mercury Risk TSD. In addition, please memoranda_fy2005_m05-03. IQ loss risk metric (i.e., an IQ loss of 1 comment on the extent to which 19 76 FR 10896 and 76 FR 17649. The first notice to 2 points or more representing a consumption rates documented in requested nominations to a Clean Air Scientific potential public health hazard). Is there Advisory Committee (CASAC) panel. Upon review Section 1.3 and in Appendix C of the of the scope of the CASAC charter (resulting from any scientifically credible alternate Mercury Risk TSD provide appropriate a public comment received in response to the first decrement in IQ that should be representation of high-end fish notice), the SAB determined that it would be more considered as a benchmark to guide consumption by the subsistence appropriate to form a panel under the SAB, rather interpretation of the IQ risk estimates than CASAC. The second notice announced this population scenarios used in modeling change and requested nominations for the SAB (see section 1.2 of the Mercury Risk TSD exposures and risk. Are there additional panel. data on consumption behavior in 20 The full list of panel members is documented 22 76 FR 39102. subsistence populations active at inland 23 at http://yosemite.epa.gov/sab/sabproduct.nsf/0/ 76 FR 50729. freshwater water bodies within the 9F048172004D93BB8525783900503486/$File/ 24 U.S. EPA–SAB, 2011. Peer Review of EPA’s Determination%20memo%20with%20addendum- Draft National-Scale Mercury Risk Assessment. continental U.S.? 05.24.11.pdf. 25 See http://yosemite.epa.gov/sab/sabpeople.nsf/ Question 8: Please comment on the 21 76 FR 29746. WebCommittees/BOARD. approach used in the risk assessment of

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assuming that a high-end fish treatment of the potential masking effect from coal and oil-fired EGUs, provided consuming population could be active of fish nutrients (e.g., omega-3 fatty that our recommendations are fully at a watershed if the ‘‘source acids and selenium) on the adverse considered in the revision of the population’’ for that fishing population neurological effects associated with assessment.’’ 28 is associated with that watershed (e.g., mercury exposure, including IQ loss The SAB report contained many at least 25 individuals of that (detail on the concentration-response recommendations for improving the Hg population are present in a U.S. Census function used in modeling IQ loss can Risk TSD, which the SAB organized into tract intersecting that watershed). Please be found in section 1.3 of the Mercury three general themes: (1) Improve the identify any additional alternative Risk TSD). clarity of the Hg Risk TSD regarding approaches for identifying the potential Question 12: Please comment on the methods and presentation of results, (2) for population exposures in watersheds degree to which key sources of expand the discussion of sources of and the strengths and limitations uncertainty and variability associated variability and uncertainty, and (3) de- associated with these alternative with the risk assessment have been emphasize IQ loss as an endpoint. In the approaches (additional detail on how identified and the degree to which they following subsection, we provide EPA’s EPA assessed where specific high- are sufficiently characterized. response to these recommendations. consuming fisher populations might be Question 13: Please comment on the draft Mercury Risk TSD’s discussion of 4. The EPA’s Responses to Peer Review active is provided in section 1.3 and Recommendations Appendix C of the Mercury Risk TSD). analytical results for each component of Question 9: Please comment on the the analysis. For each of the In response to the peer review, the draft risk assessment’s characterization components below, please comment on EPA has substantially revised the Hg of the limitations and uncertainty the extent to which EPA’s observations Risk TSD. The revised Hg Risk TSD associated with application of the are supported by the analytical results addresses all of the recommendations Mercury Maps approach (including the presented and whether there is a from the SAB and includes a detailed assumption of proportionality between sufficient characterization of list of the specific revisions made to the changes in mercury deposition over uncertainty, variability, and data Hg Risk TSD. Revisions in response to watersheds and associated changes in limitations, taking into account the the main recommendations are fish tissue MeHg levels) in the risk models and data used: Mercury summarized below. Italicized assessment. Please comment on how the deposition from U.S. EGUs, fish tissue statements are the SAB’s output of CMAQ [Community MeHg concentrations, patterns of Hg recommendations, which are followed Multiscale Air Quality] modeling has deposition with HG fish tissue data, by EPA’s response. been integrated into the analysis to percentile risk estimates, and number • The watershed-focus of the Hg Risk estimate changes in fish tissue MeHg and frequency of watersheds with TSD should be clearly stated early in the levels and in the exposures and risks populations potentially at risk due to introduction to the document. We have associated with the EGU-related fish U.S. EGU mercury emissions. stated clearly in the introduction to the tissue MeHg fraction (e.g., matching of Question 14: Please comment on the revised Hg Risk TSD that the focus of spatial and temporal resolution between degree to which the final summary of the analysis is on scenarios of high fish CMAQ modeling and HUC12 key observations in Section 2.8 is consumption by subsistence level watersheds). Given the national scale of supported by the analytical results fishing populations, assessed at the analysis, are there recommended presented. In addition, please comment watersheds where there is the potential alternatives to the Mercury Maps on the degree to which the level of for such subsistence fishing activity. approach that could have been used to confidence and precision in the overall Specifically, we modeled risk for a set link modeled estimates of mercury analysis is sufficient to support use of of subsistence fisher scenarios at those deposition to monitored MeHg fish the risk characterization framework watersheds where (a) we have measured tissue levels for all the watersheds described on page 18. fish tissue Hg data and (b) it is evaluated? (additional detail on the reasonable to assume that subsistence- 3. Summary of Peer Review Findings Mercury Maps approach and its level fishing activity could occur. We application in the risk assessment is and Recommendations emphasize the point that the analysis is presented in section 1.3 and Appendix The SAB was generally supportive of not a representative population- E of the Mercury Risk TSD). EPA’s approach.26 The SAB concluded, weighted assessment of risk. Rather, it is Question 10: Please comment on the ‘‘[i]n summary, based on its review of based on evaluating these potential EPA’s approach of excluding the draft Technical Support Document exposure scenarios. watersheds with significant non-air and additional information provided by • Because IQ does not fully capture loadings of mercury as a method to EPA representatives during the public the range of neurodevelopmental effects reduce uncertainty associated with meetings, the SAB supports the overall associated with Hg exposure, analysis of application of the Mercury Maps design of and approach to the risk this endpoint should be deemphasized approach. Are there additional criteria assessment and finds that it should (and moved to an appendix) and that should be considered in including provide an objective, reasonable, and primary focus should be placed on the or excluding watersheds? credible determination of the potential MeHg RfD-based hazard quotient Question 11: Please comment on the for a public health hazard from mercury metric. We modified the structure of the specification of the concentration- emitted from U.S. EGUs.’’ 27 The SAB revised Hg Risk TSD accordingly. response function used in modeling IQ further concluded, ‘‘[t]he SAB regards • Clarify the rationale for using a loss. Please comment on whether EPA, the design of the risk assessment as Hazard Quotient (HQ) at or above 1.5 as as part of uncertainty characterization, suitable for its intended purpose, to the basis for selecting potentially should consider alternative inform decision-making regarding an impacted watersheds. The SAB fully concentration-response functions in ‘appropriate and necessary finding’ for supported using HQ as the risk metric, addition to the model used in the risk regulation of hazardous air pollutants but we revised the discussion in the Hg assessment. Please comment on the Risk TSD to clarify why we selected 1.5 extent to which available data and 26 U.S. EPA–SAB, 2011. methods support a quantitative 27 Id. 28 Id.

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as the benchmark. We clarified that dataset (e.g., distribution of fish tissue address the caveats identified by the exposures above the RfD (i.e., an HQ sample size and number of species SAB. The uncertainty discussion now above one) represent increasing risk of across the watershed-level estimates). explains (1) that high-end consumption neurological health effects.29 We further • Determine whether there is rates for South Carolina reflect small clarified that the HQ is calculated to additional (more recent) fish tissue data sample sizes, and therefore may be more only one significant digit, based on the for key states including Pennsylvania, uncertain, (2) that the consumption precision in the underlying RfD New Jersey, Kentucky and Illinois where surveys underlying the studies are older calculations. As a result, rounding U.S. EGUs Hg deposition may be more (i.e., mostly based on survey data from convention requires that any values at significant. We expanded the fish tissue the 1990s) and behavior may have or above 1.5 be expressed as an HQ of dataset by incorporating additional fish changed (i.e., consumption rates may 2, while any values below 1.5 (e.g., 1.49) tissue data from the National Listing of have changed since the surveys were be rounded to an HQ of 1. Thus, MeHg Fish Advisories (NLFA), which conducted), and (3) that consumption exposures leading to an HQ at or above included additional data for four states rates used in the Hg Risk TSD are 1.5 for pregnant women are considered (MI, NJ, PA, and MN). We also obtained annualized rather than seasonal rates above the RfD and are associated with additional data for Wisconsin. These and thus contribute little to overall increased risk of neurological health additional data expanded the number of uncertainty. None of these sources of effects in children born to those watersheds in the analysis from 2,317 to uncertainty is associated with a mothers. 3,141, an increase of 36 percent. The particular directional bias (e.g., neither • Regarding the fish tissue dataset additional watersheds improve coverage systematically higher nor lower risk). used in the Hg Risk TSD, clarify which in areas with high levels of U.S. EGU- • Verify whether the consumption species of Hg is reflected in the attributable Hg deposition, and thus rates are daily values expressed as underlying samples and discuss the increase our confidence in the overall annual averages and whether they are implications of differences across states results of the Hg Risk TSD. ‘‘as caught’’ or ‘‘as prepared.’’ We in sampling protocols in introducing • Include additional discussion of the carefully reviewed the studies bias into the analysis. We clarified that potential that the low sampling rates underlying the fish consumption rates in most cases, the fish tissue is reflected across many of the watersheds used in the Hg Risk TSD and verified measured for total Hg. Furthermore, may low-bias the 75th percentile fish that the rates are annual averages of the based on the scientific literature,30 it is tissue Hg estimates used in estimating daily consumption rates and that they reasonable to assume that more than potential exposures. In addition, represent as prepared estimates. We also 90 percent of fish tissue Hg is MeHg. include a sensitivity analysis using the expanded the explanation of the Therefore, we incorporated an Hg 50th percentile estimates to provide a exposure calculations to describe more conversion factor 31 into our exposure bound on the risk. The SAB expressed completely the exposure factors and calculations to account for the fraction support for the use of the 75th equation used to generate the average of total Hg that is MeHg in fish. We also percentile fish tissue Hg value in the Hg daily MeHg intake estimates for the expanded the discussion of uncertainty Risk TSD, while recommending subsistence scenarios. • to address the potential for different additional discussion of the issue. We Explain the criteria for exclusion of sampling protocols across states to provided additional description of the fish less than 7 inches in length from introduce bias into the Hg Risk TSD. fish tissue dataset, including analysis. We provided the rationale for • Additional detail should be distribution of sample sizes and fish the 7-inch cutoff for edible fish used in provided on the characteristics of the species across the watersheds, and an the Hg Risk TSD. Seven inches fish tissue Hg dataset, including its improved discussion of uncertainty and represents a minimum size limit for a derivation and the distribution of potential low bias resulting from number of key edible freshwater fish specific attributes across the dataset estimation of the 75th percentile fish species established at the state level. For (e.g., number of fish tissue samples and tissue levels. We also included a example, Pennsylvania establishes 7 number of different waterbodies in a sensitivity analysis that used the 50th inches as the minimum size limit for watershed, number of species reflected percentile watershed-level fish tissue Hg both trout and salmon (other edible fish across watersheds). We included level. This sensitivity analysis showed species such as bass, walleye and additional figures and tables describing that using the 50th percentile estimates northern pike have higher minimum the derivation of the watershed-level resulted in a decrease in the number size limits). The impact of the 7-inch fish tissue Hg dataset, including the and percentage of modeled watersheds cutoff is likely to be quite small, as only filtering steps applied to the original with populations potentially at-risk 6 percent of potential fish samples were from U.S. EGU-attributable MeHg excluded due to this criterion. water body level data and the additional • steps taken to generate the watershed- exposures, from 29 percent of Identify the number of watersheds level fish tissue Hg percentile estimates. watersheds exceeding either risk metric excluded from the analysis due to the In addition, we included tables (i.e., MeHg exposure from U.S. EGUs criterion for excluding watersheds with summarizing key attributes of the alone exceeds the RfD or total MeHg less than 25 members of a source exposure exceeds the RfD and U.S. population. The SAB was generally 29 As stated in the preamble to the proposal, EGUs contribute at least 5 percent) in supportive of the approach used for based on the current literature, exposures above the the revised Hg Risk TSD to 26 percent identifying watersheds with the RfD contribute to risk of adverse effects. in the sensitivity analysis in the revised potential for subsistence activity, while 30 See the literature summary in Chapter 4 of U.S. Hg Risk TSD. recommending additional information EPA. 2000. Guidance for Assessing Chemical • Expand the discussion of caveats on the results of applying the approach. Contaminant Data for Use in Fish Advisories. Office of Science and Technology, Office of Water, associated with the fish consumption We added a figure to illustrate the Washington, DC EPA 823–B–00–007. rates used in the analysis. The SAB was number of watersheds with fish tissue 31 In the Hg Risk TSD accompanying the proposed generally supportive of the consumption Hg data used to model risk for each of rule, we assumed that 100 percent of Hg in fish was rates used, while recommending the subsistence fishing scenarios. For all MeHg. We derived the 0.95 conversion factor for the revised Hg Risk TSD to reflect that most studies additional discussion of caveats. We scenarios except the female subsistence show that more than 90 percent of total Hg in fish expanded the discussion of uncertainty fishing scenario, the exposure scenarios is MeHg. See Chapter 4 of U.S. EPA, 2000. related to the fish consumption rates to significantly limited the number of

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watersheds. Because the female sources of uncertainty may result in would substantially change the risk subsistence fishing scenario does not potential bias in the estimate of results given the stated goal of the differentiate with regard to ethnicity or exposure associated with current analysis to identify watersheds where socio-economic status (SES), we applied deposition. If the fish tissue Hg levels potential exposures to MeHg from self- this scenario to all regions of the are too high due to either previous Hg caught fish consumption could exceed country and to all watersheds with fish deposition or non-air sources of Hg, the RfD. tissue Hg data. This reflects our then the absolute level of exposure • Additional sources of uncertainty assumption that, given the generalized attributed to both total Hg deposition should be discussed in terms of their nature of the female subsistence fishing and U.S. EGU-attributable Hg deposition potential impact on risk estimates. scenario, it is reasonable to assume that will be biased high. However, the These include: (1) Emissions inventory it could potentially occur at any percent contribution from U.S. EGUs used in projecting total and U.S. EGU- watershed with fish tissue Hg data. The will not be affected as it depends attributable Hg deposition, including female subsistence fishing scenario entirely on deposition. The EPA took the projection of reductions in U.S. EGU included in the revised risk assessment steps to minimize the potential for these emissions for the 2016 scenario, (2) air is similar to the high-consuming female biases by (1) only using fish tissue Hg quality modeling with CMAQ including 32 scenario included in the Hg Risk TSD. samples from after 1999, and (2) the prediction of future air quality However, the female subsistence fishing screening out watersheds that either scenarios, (3) ability of the Mercury scenario is applied to all watersheds, contained active gold mines or had Maps-based approach for relating Hg while in the scenario for the high- other substantial non-U.S. EGU deposition to MeHg in fish to capture Hg consuming low-income female angler, anthropogenic emissions of Hg. The hotspots, (4) the limited coverage that we only evaluated watersheds with a SAB concluded that the EPA’s approach we have with fish tissue Hg data for population of at least 25 low-income to minimizing the potential for these watersheds in the U.S. and implications females. The female subsistence fishing biases to affect the results of the Hg Risk for the Hg Risk TSD, (5) the preparation scenario provides greater coverage TSD is sound. In addition, we factor used to estimate ‘‘as consumed’’ geographically than the high-consuming conducted several sensitivity analyses fish tissue Hg levels, (6) the low-income female scenario. As to gauge the impact of excluding proportionality assumption used to described in the revised Hg Risk TSD, watersheds with the potential for non- relate changes in Hg deposition to the EPA made this change in response EGU Hg loading. We found that the changes in fish tissue Hg levels at the to SAB’s concerns regarding the estimates of the percent of modeled watershed-level, (7) characterization of potential exclusion of watersheds with watersheds with populations potentially the spatial location of subsistence fisher fewer than 25 individuals and regarding at-risk were largely insensitive to these populations (including the degree to coverage for high-end recreational fish exclusions, suggesting that any potential which these provide coverage for high- consumption.33 biases from including watersheds with • consuming recreational fishers), and (8) Enhance the discussion of the potential non-air Hg loadings are likely application of the RfD to low SES assumption of a linear relationship to be small. populations and concerns that this between changes in Hg deposition and • Additional sources of variability could low-bias the risk estimates. We changes in fish tissue Hg at the should be discussed in terms of the expanded the discussion of sources of watershed level, including providing degree to which they are reflected in the uncertainty presented in the revised citations to more recent studies design of the risk assessment and the TSD to address more fully these sources supporting the proportional relationship impact that they might have on risk of uncertainty and the potential impact between changes in Hg deposition and estimates. These include: (1) The on risk estimates. Regarding these eight changes in MeHg fish tissue levels. The geographic patterns of populations of additional sources of uncertainty, we SAB supported the assumption of a subsistence fishers, including how this have (1) evaluated the uncertainties in linear relationship between changes in factor interacts with the limited the emissions and determined that Hg deposition and changes in fish tissue coverage we have for watersheds with while an important source of Hg at the watershed level, while our fish tissue Hg data, (2) the protocols uncertainty, we are not able to quantify recommending additional supporting used by states in collecting fish tissue emissions uncertainty in the risk language. We expanded our discussion Hg data, (3) body weights for analysis, but have determined that the of the scientific basis for the subsistence fishing populations and the emissions inventories and emissions proportionality assumption and added impact that this might have on exposure models represent the best available citations for the more recent studies estimates, and (4) preparation and methods for predicting Hg emissions in supporting the assumption. We also cooking methods which affect the the U.S., (2) evaluated the uncertainties expanded the discussion of conversion of fish tissue Hg levels (as in the Hg deposition predictions and uncertainties associated with this measured) into ‘‘as consumed’’ values. determined that while an important assumption, including uncertainties We expanded the discussion of sources source of uncertainty, we are not able to related to the potential for sampled fish of variability in the revised Hg Risk TSD quantify uncertainty in Hg deposition in tissue Hg level to reflect previous Hg to more fully address these sources of the Hg Risk TSD. Moreover, the CMAQ deposition, and the potential for non-air variability. The Hg Risk TSD model used to estimate deposition is sources of Hg to contribute to sampled quantitatively reflected many aspects of based on peer reviewed science and fish tissue Hg levels. Each of these variability, including spatial and represents the best available method for temporal variability in Hg emissions, Hg predicting Hg deposition in the U.S., (3) 32 In the Revised Hg Risk TSD, this population is also referred to as the ‘‘typical female subsistence deposition, fish tissue Hg levels, and evaluated the ability of the Mercury consumer.’’ subsistence behavior. After evaluating Maps-based approach for relating Hg 33 This change led to a very small increase in the the aspects of variability assessed deposition to MeHg in fish to capture number of watersheds with populations potentially qualitatively in the Hg Risk TSD such as Hg hotspots and determined that while at-risk. In the Hg Risk TSD accompanying the finer resolution deposition modeling proposed rule, approximately 4 percent of modeled temporal response in fish tissue, we do watersheds were excluded based on the SES-based not believe that quantitatively might reveal additional areas with filtering criteria. incorporating any of these aspects elevated deposition, the 12 kilometer

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(km) deposition modeling matches well C. Summary of Results of Revised Hg the total percent of modeled watersheds with the watershed size selected for the Risk TSD of Risks to Populations With with populations potentially at-risk analysis, and thus the use of 12 km High Levels of Self-Caught Fish using the expanded geographic coverage deposition estimates with the Mercury Consumption of watersheds provides additional Maps based approach will not be a large Based on the recommendations we confidence that emissions of Hg from source of uncertainty, (4) evaluated the received from the SAB, we revised the U.S. EGUs pose a hazard to public limited coverage that we have with fish quantitative analysis of risk to health. For the 99th percentile tissue Hg data for watersheds in the U.S. subsistence fishing populations with consumption scenario, the percent of and implications for the Hg Risk TSD high levels of fish consumption. Our modeled watersheds with populations and based on the SAB’s revision to the quantitative risk results potentially at-risk from total potential recommendations, we supplemented the reflects three key recommendations exposures to MeHg that exceed the RfD coverage of watersheds by obtaining from the SAB, including (1) addition of and U.S. EGUs contribute at least 5 additional fish tissue Hg samples for 824 watersheds based on additional fish percent increased from 22 percent to 24 areas heavily impacted by U.S. EGU tissue Hg sample data we obtained from percent. For the 99th percentile deposition, thus reducing the states and the National Listing of Fish consumption scenario, the percent of uncertainty in the analysis, (5) Advisories, (2) application of a 0.95 modeled watersheds with populations evaluated the uncertainty in the adjustment factor to the reported fish potentially at-risk based on Hg preparation factor and determined that tissue Hg concentrations to account for deposition from U.S. EGUs alone the level of uncertainty is low, and as the fraction that is MeHg, and (3) decreased from 12 percent to 10 percent. such would have minimal impact on the inclusion of all watersheds with fish The additional sensitivity analyses risk estimates, (6) evaluated the samples that meet the filtering criteria 34 conducted in response to the SAB peer uncertainty resulting from the in representing potential exposures review showed that the estimates of the proportionality assumption used to associated with increased risk of percent of modeled watersheds with relate changes in Hg deposition to neurologic health effects for female populations potentially at-risk are changes in fish tissue Hg levels at the subsistence fishing populations. robust to alternative assumptions about Based on these revisions, our watershed-level, and determined, based both the watersheds included in the estimates of the number and percent of both on quantitative sensitivity analyses analysis and the selection of the 50th modeled watersheds with populations and qualitative assessments, that this percentile or 75th percentile fish tissue potentially at-risk from exposure to source of uncertainty is not likely to Hg level. Sensitivity analyses excluding EGU-attributable MeHg changed from greatly influence the results, and is not entire states with the potential for those presented in the preamble to the historical loadings of Hg from non-air likely to have a specific directional bias, 35 proposed rule. For the 99th percentile sources 36 resulted in an increase from (7) evaluated the uncertainty related to consumption scenario, the number of characterization of the spatial locations 29 percent to 33 percent in the total watersheds with fish tissue Hg samples percent of modeled watersheds with of subsistence populations and where subsistence fishing populations determined that uncertainty could be populations potentially at-risk may be at-risk from exposure to EGU- exceeding either risk metric (i.e., U.S. reduced by focusing the risk estimates attributable MeHg increased from 672 to on female subsistence fishing EGUs alone or total potential exposures 917 (an increase of 36 percent). For this to MeHg exceed the RfD and U.S. EGUs populations, which are assumed to have same scenario, the total percent of the potential to fish in all watersheds, contribute at least 5 percent). Including modeled watersheds with populations only watersheds in the top 25th in response to SAB’s concerns regarding potentially at-risk from either risk potential exclusion of watersheds with percentile of U.S. EGU deposition metric (i.e., MeHg exposure from U.S. resulted in an increase in the total fewer than 25 individuals and (8) EGUs alone exceeds the RfD or total percent of modeled watersheds with evaluated the potential impact of the MeHg exposure exceeds the RfD and populations potentially at-risk uncertainty in application of the RfD to U.S. EGUs contribute at least 5 percent) exceeding either risk metric, from 29 low SES populations. The EPA increased from 28 percent estimated at percent to 30 percent. Using the 50th determined that due to the method used proposal to 29 percent after addressing percentile fish tissue Hg level resulted in calculating the RfD, we have SAB recommendations. The increase in confidence that the RfD provides in a decrease in the total percent of modeled watersheds with populations protection for low SES populations. 34 The watersheds were filtered to exclude potentially at-risk exceeding either risk • watersheds that: (a) Were not freshwater, (b) did not Expand the sensitivity analyses have fish sampling data since 2000, (c) did not have metric, from 29 percent to 26 percent. (over those included in the original risk fish larger than 7 inches in length, (d) contained On balance, these sensitivity analyses assessment) to address uncertainty active gold mines or (e) had substantial non-air Hg do not substantially reduce the percent related to the use of the 75th percentile loading. 35 Since the time of the analyses conducted in of modeled watersheds with fish tissue Hg value (at each watershed) support of the proposed rule, the EPA updated IPM populations potentially at-risk, and thus as the core risk estimate. Based on the modeling to reflect the most recently available confirm the finding that Hg emissions SAB’s recommendation, we added a information, including public comments and the from U.S. EGUs pose a hazard to public sensitivity analysis using the median final CSAPR (see IPM Documentation for further details on these updates, which is available in the health. In fact, given the broader fish tissue Hg estimate (at the watershed docket). Compared to the modeling conducted at coverage of modeled watersheds in the level). This sensitivity analysis showed proposal, these updates are projected to result in revised analysis, we have even greater that use of the median fish tissue Hg greater reductions in criteria pollutants, and also to confidence in our finding that Hg concentration instead of the 75th have a slightly greater impact on U.S. EGU Hg emissions. Based on the revised projection for 2016, percentile resulted in a relatively small the EPA estimates that U.S. EGUs would emit 27 36 The SAB noted that areas with substantially decrease (i.e., 10 percent) in the tons of Hg, as compared to the 29 tons we modeled elevated fish tissue Hg levels could also be estimates of watersheds with for the Hg Risk TSD. We do not expect this 2 ton characterized by lakes and rivers with high natural populations potentially at-risk, and did difference to substantially change the mercury risks methylation rates, and thus some of the states we reported in the preamble to the proposed rule, as excluded for this sensitivity analysis might not have not substantially change the conclusions this represents less than a 10 percent reduction in fish tissue Hg levels that reflect non-U.S. EGU Hg of the risk assessment. Hg emissions. loadings.

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emissions from U.S. EGUs pose a hazard government, academic and the private approaches 38 to derive unit risk to public health. sector to review of the methods for estimates that may be more developing inhalation cancer risk D. Peer Review of the Approach for scientifically defensible than those used estimates associated with emissions of Estimating Cancer Risks Associated in past analyses. Which of the options Cr and Ni compounds from coal- and With Cr and Ni Emissions in the U.S. presented would result in more accurate EGU Case Studies of Cancer and Non- oil-fired EGUs in support of the and defensible characterization of risks Cancer Inhalation Risks for Non-Hg appropriate and necessary finding. The from exposure to Ni and Ni compounds? HAP and EPA Response approaches and rationale for the Are there alternative approaches that technical and scientific considerations EPA should consider? As explained in the preamble to the used to derive inhalation cancer risks proposed rule, the EPA submitted for were summarized in the draft document 3. Summary of Peer Review Findings peer review its characterization of the entitled, ‘‘Methods to Develop and Recommendations chemical speciation for the emissions of Inhalation Cancer Risk Estimates for Regarding Cr and Cr compounds, all Cr and Ni used in the non-Hg HAP Chromium and Nickel Compounds.’’ three reviewers considered Cr(VI) as the inhalation risk case studies. The The peer reviewers received several remaining aspects of the non-Hg HAP charge questions (three questions on Cr species likely to be driving cancer risks case study risk assessments used and two questions on Ni, which are based on solid evidence from the health methods that were previously peer provided below) on the technical and effects database for Cr and Cr reviewed. Specifically, the scientific relevance of the approaches compounds. All three authors also methodologies used to conduct the non- used to develop the inhalation unit risk considered EPA’s use of the average of Hg case studies are consistent with estimates. The EPA also provided the range of the available speciation those used to conduct inhalation risk information on Cr speciation profiles for data (i.e., 12 percent and 18 percent assessments under EPA’s Risk and different industrial sources, as well as Cr(VI) contained in coal- and oil-fired Technology Review (RTR) program. information on the Ni speciation of PM EGUs, respectively) as a reasonable Because the RTR assessments are from oil-fired EGUs. approach for the derivation of default considered to be highly influential speciation profiles to be used when science assessments, the methodologies 2. Peer Review Charge Questions there is no speciation data available. All used to conduct them were subject to a Below, we present the charge reviewers agreed that there is high peer review by the SAB in 2009. The questions posed to the peer reviewers to uncertainty associated with the SAB issued its peer review report in help guide their review and variability in the speciation data 37 May 2010. The report endorsed the development of recommendations to available for Cr (e.g., range of risk assessment methodologies used in EPA on key issues relevant to the approximately 4 to 23 percent Cr(VI) the program, and made a number of characterization of risks from EGU from coal-fired units). One of the technical recommendations for EPA to emissions containing either Cr or Ni reviewers recommended several consider as the RTR program evolves. compounds. additional studies for EPA’s The EPA’s case studies identified Cr The EPA asked three questions consideration; the EPA considered these and Ni emissions as the key drivers of regarding Cr and Cr compounds: in finalizing the report. the estimated inhalation cancer risks for EGUs. Because these results hinged on Question 1: Do EPA’s judgments Regarding Ni and Ni compounds, the specific scientific interpretations of data related to speciated Cr emissions reviewers agreed with the views of the used to characterize EGU emissions of adequately take into account the international scientific bodies, which Cr and Ni, the EPA conducted a letter available Cr speciation data? consider Ni compounds carcinogenic as peer review of its analysis and Question 2: Has EPA selected the a group. One reviewer recommended interpretation of those data relative to species of Cr (i.e., hexavalent Cr, Cr(VI)) that the EPA review several additional the quantification of inhalation risks that accurately represents the toxicity of Ni speciation data that suggests that associated with Cr and Ni emissions Cr and Cr compounds? sulfidic Ni compounds (which the from U.S. EGUs. The following sections Question 3: Are the assumptions used reviewer considered as the most potent describe the peer review process, in past analysis scientifically defensible, carcinogens within the group of all Ni enumerate the peer review charge and are there alternatives that EPA compounds) are present at low levels in questions presented to the peer review should consider for future analysis? emissions from EGUs. In addition, this panel, summarize the key The EPA asked two questions reviewer pointed out that there is a recommendations from the peer review, regarding Ni and Ni compounds: recently proposed model that may and summarize our responses to those Question 1: Do EPA’s judgments explain the differences in carcinogenic recommendations. related to speciated Ni emissions potential across Ni compounds. 1. Summary of Peer Review Process adequately take into account available 4. The EPA’s Responses to Peer Review speciation data, including recent Recommendations The EPA asked three independent, industry spectrometry studies? external peer reviewers representing Question 2: Based on the speciation We summarize EPA’s basic responses to the peer review comments below, 37 U.S. Environmental Protection Agency— information available and on what we Science Advisory Board (U.S. EPA–SAB). 2010. know about the health effects of Ni and first for Cr-related issues, and second for Review of EPA’s draft entitled, ‘‘Risk and Ni compounds, and taking into account Ni-related issues, which are reflected in Technology Review (RTR) Risk Assessment the existing Unit Risk Estimates (URE) the revised document.39 Methodologies: For Review by the EPA’s Science Advisory Board with Case Studies—MACT I values (i.e., values derived for EPA’s Petroleum Refining Sources and Portland Cement Integrated Risk Information System 38 See section 3.3 of U.S. Environmental Manufacturing’’. EPA–SAB–10–007. May. Available (IRIS), California Environmental Protection Agency (U.S. EPA). 2011c. Methods to on-line at: http://yosemite.epa.gov/sab/ Protection Agency (Cal EPA) and Texas Develop Inhalation Cancer Risk Estimates for sabproduct.nsf/ Chromium and Nickel Compounds. Office of Air 4AB3966E263D943A8525771F00668381/$File/EPA- Commission on Environmental Quality Quality Planning and Standards. October. SAB-10-007-unsigned.pdf. (TCEQ)), the EPA has provided several 39 U.S. EPA, 2011c.

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a. Cr and Cr Compounds refining industries may cause cancer in to use a health protective approach by In agreement with the peer reviewers humans, and there is no reason to applying 100 percent of the current IRIS and based on the health effects expect anything different from this for URE for Ni subsulfide, rather than information available for Cr, the EPA mixtures of Ni compounds from other assuming that 65 percent of the total assigns high confidence in the emission sources. One of the reviewers mass of emitted Ni might be Ni assumption that Cr(VI) is the suggested we consider views by some subsulfide, as used in previous analyses. carcinogenic species driving the risk of authors that believe that water soluble We used the IRIS URE value because Cr-emitting facilities. In agreement with Ni, such as Ni sulfate, should not be IRIS values are preferred given the the reviews, the EPA considers considered a human carcinogen. This conceptual consistency with EPA risk derivation of default speciation profiles view is based primarily on a negative Ni assessment guidelines and the level of based on the mass of Cr(VI) a reasonable sulfate 2-year rodent bioassay by the peer review that such values receive. approach. As suggested by one of the National Toxicology Program (NTP) We used 100 percent of the IRIS value reviewers, the EPA reviewed two (which is different from the positive 2- because of the concerns about the potentially relevant studies, one of year NTP bioassay for Ni potential carcinogenicity of all forms of which showed coal combustion subsulfide).42 43 44 One review article Ni raised by the major national and emissions containing as much as 43 identifies the discrepancies between the international scientific bodies, and percent Cr(VI),40 which suggests that the animal and human data (i.e., from recommendations of the peer reviewers. EPA’s quantitative approach could studies of cancers in workers inhaling Nevertheless, taking into account that actually underestimate Cr(VI) inhalation certain forms of Ni versus inhalation there are potential differences in risks. However, the other study studies suggesting different carcinogenic toxicity and/or carcinogenic potential reviewed by EPA on speciation of Cr in potential in rodents with different Ni across the different Ni compounds, and coal combustion showed Cr(VI) compounds) and states that the given that two URE values have been percentage levels close to detection epidemiological data available clearly derived for exposure to mixtures of Ni limits (i.e., 3 to 5 percent of total Cr, support an association between Ni and compounds that are two to three fold which was close to the limit of detection increased cancer risk, although the lower than the IRIS URE for Ni in this study).41 Thus, the more recent article acknowledges that the data are subsulfide, the EPA also considers it speciation data available is unlikely to weakest regarding water soluble Ni. In reasonable to use a value that is 50 reduce the uncertainty of the Cr addition, the EPA identified a recent percent of the IRIS URE for Ni speciation analyses used by EPA as the review 45 that highlights the robustness subsulfide for providing an estimate of bases for risk characterization analysis. and consistency of the epidemiological the lower end of a plausible range of In agreement with the peer reviewers, evidence across several decades cancer potency values for different the EPA also recognizes that the showing associations between exposure mixtures of Ni compounds. confidence in the default speciation to Ni and Ni compounds (including Ni Although this report focused profiles is low because the profiles are sulfate) and cancer. primarily on cancer risks associated based on a limited data set with a wide Regarding the second charge question with emissions containing Ni range of percentages of Cr(VI) across the on Ni compounds, two reviewers compounds, it is important to note that different samples. suggested using the URE derived by the comparative quantitative analyses of TCEQ 46 for all Ni compounds as a non-cancer toxicity of Ni compounds b. Ni and Ni Compounds indicate that Ni sulfate is as toxic or group, rather than the one derived by more toxic than Ni subsulfide or Ni Based on the views of the major the Integrated Risk Information System oxide which does not support the scientific bodies mentioned above and (IRIS, 1991) 47 specifically for Ni notion that the solubility of Ni the peer reviewers that commented on subsulfide. The third reviewer did not compounds is a strong determinant of EPA’s approaches to risk comment on an alternative approach. its toxicity.48 49 characterization of Ni compounds, the Considering this, to develop our EPA considers all Ni compounds to be primary risk estimate, the EPA decided E. Summary of Results of Revised U.S. carcinogenic as a group and the EPA EGU Case Studies of Cancer and Non- does not consider Ni speciation or Ni 42 Oller A. 2002. ‘‘Respiratory carcinogenicity Cancer Inhalation Risks for Non-Hg solubility to be strong determinants of assessment of soluble nickel compounds.’’ Environ HAP Ni carcinogenicity. These scientific Health Perspect. 110:841–844. bodies also recognize that based on the 43 Heller JG, Thornhill PG, Conard BR. 2009. Based on the results of the peer data available, the precise Ni ‘‘New views on the hypothesis of respiratory cancer review and public comments on the risk from soluble nickel exposure; and non-Hg case study chronic inhalation compound(s) responsible for the reconsideration of this risk’s historical sources in carcinogenic effects in humans is not nickel refineries.’’ J Occup Med Toxicol. 4:23. risk assessment, we made several always clear, and that there may be 44 Goodman JE, Prueitt RL, Thakali S, and Oller changes to the emissions estimates, differences in the potential toxicity and AR. 2011. ‘‘The nickel iron bioavailability model of dispersion modeling, and risk the carcinogenic potential of nickel-containing characterization for the modeled case carcinogenic potential across Ni substances in the lung.’’ Crit Rev Toxicol 41:142– compounds. Nevertheless, studies in study facilities. Key changes include (1) 174. changes in emissions, (2) changes in humans indicate that various mixtures 45 Grimsrud TK and Andersen A. ‘‘Evidence of of Ni compounds (including Ni sulfate, carcinogenicity in humans of water-soluble nickel stack parameters for some facilities sulfides and oxides, alone or in salts.’’ J Occup Med Toxicol. 2010. 5:1–7. Available based on new data received during the online at http://www.ossup-med.com/content/5/1/7. combination) encountered in the Ni 46 Texas Commission on Environmental Quality 48 Haber LT, Allen BC, Kimmel CA. 1998. ‘‘Non- (TCEQ). 2011. Development Support Document for Cancer Risk Assessment for Nickel Compounds: 40 Galbreath KC, Zygarlicke CJ. 2004. ‘‘Formation nickel and inorganic nickel compounds. Available Issues Associated with Dose-Response Modeling of and chemical speciation of arsenic-, chromium-, online at http://www.tceq.state.tx.us/assets/public/ Inhalation and Oral Exposures.’’ Toxicol Sci. and nickel-bearing coal combustion PM2.5,’’ Fuel implementation/tox/dsd/final/june11/ 43:213–229. _ _ Process Technol 85:701–726. nickel & compounds.pdf. 49 National Toxicology Program (NTP). 1996. 41 Huggins FE, Najih M, Huffman GP. 1999. 47 U.S. EPA, 1991. Integrated Risk Information Technical Report Series No. 454, Toxicology and ‘‘Direct speciation of chromium in coal combustion Service (IRIS) assessment for nickel subsulfide. carcinogenesis studies of nickel sulfate by-products by X-ray absorption fine structure Available at: http://www.epa.gov/iris/subst/ hexahydrate. July. Available online at http:// spectroscopy,’’ Fuel Process Technol 78:233–242. 0273.htm. ntp.niehs.nih.gov/ntp/htdocs/LT_rpts/tr454.pdf.

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public comment period, (3) use of F. Public Comments and Responses to rulemaking when making the updated versions of AERMOD and its the Appropriate and Necessary Finding appropriate and necessary finding and input processors (AERMAP, listing decision in 2000. However, the 1. Legal Aspects of Appropriate and AERMINUTE, and AERMET), and (4) commenter’s complaint is without Necessary Finding use of 100 percent of the current IRIS foundation. The CAA does not require URE for Ni subsulfide to calculate Ni- a. History of Section 112(n)(1)(A) CAA section 307(d) rulemaking for associated inhalation cancer risks Comment: One commenter provided a listing decisions. In fact, CAA section (rather than assuming that the Ni might detailed history of EPA’s regulatory 112(e)(4) specifically provides that be 65 percent as potent as Ni actions concerning EGUs and listing decisions may only be challenged subsulfide). implementation of CAA section ‘‘when the Administrator issues Based on estimated actual emissions, 112(n)(1)(A). The same commenter emission standards for such * * * the highest estimated individual implies that the EPA’s 2000 appropriate [listed] category.’’ Second, the lifetime cancer risk from any of the 16 and necessary finding and listing of commenter challenged the listing case study facilities was 20 in a million, EGUs was flawed because the Agency decision in the U.S. Court of Appeals for the District of Columbia Circuit (Court) driven by Ni emissions from the one did not comply with CAA section and, on July 26, 2001, the Court granted case study facility with oil-fired EGUs. 307(d) rulemaking process. The EPA’s motion to dismiss that action Of the facilities with coal-fired EGUs, commenter sought review of the 2000 based on the plain language of CAA five facilities had maximum individual notice in the U.S. Court of Appeals for section 112(e)(4). Moreover, in addition cancer risks greater than one in a the District of Columbia Circuit, which to the 2000 notice, the EPA clearly million 50 (the highest was five in a was dismissed by the D.C. Circuit. articulated its basis for listing EGUs in million), with the risk from four due to Utility Air Regulatory Group v. EPA, No. this proposed rule, which is consistent emissions of Cr(VI) and the risk from 01–1074 (D.C. Cir. July 26, 2001). The with CAA section 307(d), and the one due to emissions of Ni.51 There commenter then characterizes at length commenter was provided an ample were also two facilities with coal-fired the 2005 EPA action that revised the opportunity to comment. Finally, the EGUs that had maximum individual interpretation of CAA section commenter asserts that the rulemaking cancer risks equal to one in a million. 112(n)(1)(A) and, which the D.C. Circuit docket for this action is incomplete All of the facilities had non-cancer concluded illegally removed EGUs from because the Agency did not include two Target Organ Specific Hazard Index the CAA section 112(c) list of sources earlier dockets—Docket ID. No. A–92– (TOSHI) 52 values less than one, with a that must be regulated under CAA 55 and Docket ID. No. EPA–HQ–OAR– maximum TOSHI value of 0.4 (also section 112. See New Jersey v. EPA, 517 2002–0056—for the Section 112(n) driven by Ni emissions from the one F.3d 574 (D.C. Cir. 2008). The Revision Rule, 70 FR 15994 (March 29, case study facility with oil-fired EGUs). commenter notes that the D.C. Circuit did not rule on the legal correctness or 2005), and the reconsideration of the Since these case studies do not cover the sufficiency of the factual record Section 112(n) Revision Rule, 71 FR all facilities in the category, and since supporting EPA’s 2000 listing decision 33388 (June 9, 2006), respectively. The our assessment does not include the or on the factual correctness of EPA’s commenter is incorrect because EPA potential for impacts from different EGU later decision to reverse its CAA section incorporated by reference the two facilities to overlap one another (i.e., 112(n)(1)(A) determination. The dockets at issue. See EPA–HQ–OAR– these case studies only look at facilities commenter noted further that the D.C. 2009–0234–3056. in isolation), the maximum risk Circuit indicated that the listing Comment: One commenter stated that estimates from the case studies likely decision could be challenged when the the EPA has assessed the public health underestimates true maximum risks for Agency issued the final CAA section risks posed by HAP emissions from the source category. 112(d) standards pursuant to CAA coal- and oil-fired EGUs for the last 40 Based on the fact that six U.S. EGUs section 112(e)(4). The commenter years. According to the commenter, were estimated to meet or exceed the concluded by asserting that the Agency throughout that time, the EPA has come CAA section 112(c)(9) criterion of one in could not ignore the history associated to a single repeated conclusion that a million, EGUs cannot be removed with the regulation of EGUs under HAP emissions from EGUs pose little or from the list of source categories to be section 112 and that two earlier no risk to public health. Based on this regulated under CAA section 112. dockets—Docket ID. No. A–92–55 and conclusion, the EPA has properly Docket ID. No. EPA–HQ–OAR–2002– chosen not to require EGUs to install 50 A risk level of 1 in a million implies a 0056—are also part of this long expensive, new pollution control likelihood that up to one person, out of one million rulemaking effort and must be equipment to control HAP emissions. equally exposed people would contract cancer if The commenter asserts that, in this exposed continuously (24 hours per day) to the accounted for in conjunction with specific concentration over 70 years (an assumed Docket No. EPA–HQ–OAR–2009–0234 proposed rule, the EPA shifts its lifetime). This would be in addition to those cancer if all pertinent material and comments opinion on the health impacts of EGU cases that would normally occur in an unexposed are to be part of the rulemaking record. HAP emissions 180 degrees and now population of one million people. Response: The commenter seeks to impose sweeping regulatory 51 When the lower end of the cancer potency range for Ni was used to develop risk estimates, 5 characterizes the regulatory history of requirements on all power plants. of the 16 facilities had maximum cancer risks the rule EPA proposed on May 3, 2011. According to the commenter, the EPA’s exceeding 1 in a million, and the maximum To the extent that characterization is newfound concern about HAP individual cancer risk for any single facility fell to inconsistent with the lengthy regulatory emissions from EGUs is not based on 10 in a million. new and different assessments of the 52 The target-organ-specific hazard index (TOSHI) history EPA provided in the preamble to is a metric used to assess whether there is an the May 3, 2011 rule, we disagree. We public health consequences of EGU appreciable risk of deleterious (noncancer) effects to address several of the statements in HAP emissions but instead on health a specific target organ due to continuous inhalation more detail below. benefits from the reduction of non- exposures over a lifetime. If a TOSHI value is less hazardous air pollutants, primarily PM, than or equal to one, such effects are unlikely. For First, the commenter makes much of TOSHI values greater than one, there is an the fact that the EPA did not go through which the Agency is required to regulate increased risk of such effects. CAA section 307(d) notice and comment under other provisions of the CAA. One

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commenter stated that for decades, the a risk-based determination in order to utility steam generating units’’) and EPA set primary ambient air quality regulate HAP. According to the regulate EGUs under section 112 if the standards that protect public health commenter, the EPA may regulate Administrator determined in her with an adequate margin of safety, CAA substances ‘‘reasonably * * * discretion that it was appropriate and section 109(b)(1), and set secondary anticipated to result in an increase in necessary to do so. The Agency standards that are [sic] ‘‘requisite to mortality or increase in serious illness’’ complied with the statutory mandates in protect the public welfare from any to a level that protects public health CAA section 112(n)(1) in conducting the known or anticipated adverse effects with an ‘‘ample margin of safety.’’ studies and reasonably exercised its associated with the presence of such air According to the commenter, the EPA discretion in making the appropriate pollutant in the ambient air,’’ CAA has regulated a number of HAP emitted and necessary finding. 109(b)(2). The commenter notes that from industrial source categories other We acknowledge that Congress treated even if EPA now views those past PM than EGUs. radionuclide emissions from EGUs standards as inadequate, the EPA has As for EGUs, according to the differently. For radionuclides from ongoing regulatory proceedings in commenter, the EPA found that the EGUs (and certain other sources), which it can address any perceived combustion of fossil fuels produces Congress included CAA section health concerns. The commenter extremely small emissions of a broad 112(q)(3), which authorizes but does not concludes that regulation of EGU HAP variety of substances that are present in require the Agency to maintain the emissions under CAA section 112 is an trace amounts in fuels and that are regulations of radionuclides in effect unlawful way to address those concerns. removed from the gas stream by control prior to the 1990 amendments. The fact Response: The commenter is incorrect equipment installed to satisfy other that Congress made an exception for in its assertion that the Agency has CAA requirements. The commenter radionuclides and no other HAP from consistently concluded that HAP stated that the EPA, in past reviews, EGUs further demonstrates that the emissions from EGUs do not present a found that these HAP emissions did not HAP-related actions EPA took with hazard to public health. In the 2000 pose hazards to public health. See 48 FR regard to EGUs prior to the 1990 finding, the Agency concluded that HAP 15076, 15085 (1983) (radionuclides). the amendments to the CAA are not emissions from coal- and oil-fired EGUs commenter further stated that ‘‘[i]n the germane. do pose a hazard to public health and case of Hg specifically, the EPA found As for the commenter’s statements determined that it was appropriate and that ‘‘coal-fired power plants * * * do about Hg emissions from EGUs, we find necessary to regulate such units under not emit mercury in such quantities that their conclusions wholly inconsistent CAA section 112. As a result of that they are likely to cause ambient mercury with CAA section 112(n)(1). That finding, the EPA added coal- and oil- concentration to exceed’’ a level that provision is titled ‘‘Electric utility steam fired EGUs to the CAA section 112(c) ‘‘will protect public health with an generating units,’’ and it directs EPA to list of source categories for which ample margin of safety.’’ 40 FR 48297– conduct two Hg-specific studies. See emission standards are to be established 98 (October 19, 1975) (Hg); 52 FR 8724, CAA sections 112(n)(1)(B) and pursuant to CAA section 112(d). 8725 (March. 19, 1987) (reaffirming Hg 112(n)(1)(C). The commenter’s Further, in support of the proposed rule, conclusion). suggestion that the EPA could or should the EPA conducted additional extensive According to the commenter, in the rely on assessments of Hg from EGUs quantitative and qualitative analyses, late 1980s, the EPA was concerned that conducted prior to the 1990 which confirm that it remains its prior risk assessments of individual amendments is not tenable. appropriate and necessary to regulate HAP emissions from fossil-fuel-fired Finally, the commenter stated that the EGUs under CAA section 112. Among power plants may not reflect the total EPA conducted a risk assessment of all other things, those analyses demonstrate risks posed by all HAP emitted by those HAP from EGUs prior to the 1990 that emissions from coal- and oil-fired sources. The commenter states that the amendments and that the Agency did EGUs continue to pose a hazard to EPA modeled the risks posed by all not identify any HAP that failed the public health. The commenter also fails HAP emitted by power plants (very ‘‘ample margin of safety’’ test. The to note that the EPA found that HAP much like the analyses the Agency commenter did not cite the study or emissions from EGUs pose a hazard to would conduct for the Utility Study ten provide any information to support the the environment as well. years later). The commenter asserts that statements so we are unable to respond The commenter seems confused about the modeling again failed to identify to the alleged study directly; however, the basis for the Agency’s appropriate threats to public health that warranted the risk assessments conducted in and necessary finding because it regulation under an ‘‘ample margin of support of the appropriate and maintains that the EPA made the safety’’ test. necessary finding, as well as the 2000 appropriate and necessary finding based Response: The commenter’s finding, demonstrate that HAP on the health co-benefits attributable to statements concerning the pre-1990 emissions from EGUs pose hazards to PM reductions that will be achieved as CAA are not relevant to the current public health and the environment. a result of the Agency’s regulation of action. Congress enacted CAA section HAP emissions from EGUs. Nowhere in 112(n)(1) as part of the 1990 b. Interpretation of ‘‘Appropriate’’ and the May 2011 proposal does EPA state amendments to the Act. That provision ‘‘Necessary’’ that it based the appropriate and requires, among other things, that the Comment: One commenter stated that necessary finding on hazards to public Agency evaluate the hazards to public in the preamble to the proposed rule, health attributable to PM emissions. The health posed by HAP emissions from the EPA sets out its ‘‘interpretation of commenter’s allegation lacks fossil-fuel fired EGUs. Had Congress the critical terms in CAA section foundation. The appropriate and concluded, as commenter appears to 112(n)(1),’’ arguing that this latest necessary finding unmistakably focuses assert, that HAP emissions from EGUs interpretation is ‘‘wholly consistent on the hazards to public health and did not pose a hazard to public health with the CAA’’ and with the Agency’s hazards to the environment associated or the environment, it defies reason that earlier ‘‘2000 finding.’’ See 76 FR 24976, with HAP emissions from EGUs. Congress would have required EPA to 24986 (May 3, 2011). The commenter Comment: One commenter stated that conduct the three studies at issue in stated that throughout the proposal EPA CAA section 112 required EPA to make CAA section 112(n)(1) (titled ‘‘Electric tries to suggest that it is returning to

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some earlier, ‘‘correct’’ interpretation of adequately address the serious public cannot be regulated differently. The CAA section 112(n)(1) set forth in its health and environmental hazards commenters conclude that the language 2000 action. See, e.g., 76 FR 24989 arising from HAP emissions from EGUs. of section 112(n)(1)(a) reflects Congress’ (‘‘The Agency’s interpretation of the The Agency also specifically noted that intent that ‘‘regulation of HAP from term ‘appropriate’ * * * is wholly ‘‘section 112 is the authority intended to EGUs was not intended to operate under consistent with the Agency’s address’’ hazards to public health and section 112(d) but was instead intended appropriate finding in 2000’’); id. at the environment posed by HAP to be tailored to the findings of the 24992 (‘‘Our interpretation of the emissions. Id. utility study mandated by section necessary finding is reasonable and The detailed interpretation set forth in 112(n)(1)(A).’’ consistent with the 2000 finding’’). the preamble to the proposed rule is Response: The commenters maintain According to the commenter, the EPA consistent with the 2000 finding, but that the Agency’s interpretation of CAA did not provide in 2000 any EPA does not assert that the section 112(n)(1) is flawed in many interpretation of what it now interpretation is in any way necessary to respects. The primary support for one characterizes as the ‘‘critical terms’’ of support the factual conclusions reached commenter’s arguments against EPA’s section 112(n)(1). See, e.g., 70 FR 15999 in the 2000 finding. Instead, we noted interpretation, including in the n.13 (the ‘‘2000 finding does not in the preamble to the proposed rule comment above, is legislative history in provide an interpretation of the phrase that our interpretation is consistent with the form of statements from one ‘after imposition of the requirements of the 2000 finding because in 2005 we Congressman, Representative Oxley. the Act’ ’’); id. at 16000/2 (in 2000, the interpreted the statute in a manner that The Supreme Court has repeatedly EPA ‘‘did not provide an interpretation was not consistent with the 2000 stated that the statements of one of the term ‘appropriate’ ’’); 76 FR 24992 finding. The commenter has provided legislator alone should not be given (the ‘‘Agency did not expressly interpret no legal support for its position that the much weight. See Brock v. Pierce the term necessary in the 2000 Agency erred in interpreting the statute County, 476 U.S. 253, 263 (1986) finding’’). The commenter believes that in a manner that is consistent with a (finding that ‘‘statements by individual for that reason alone, it is impossible to prior factual finding. legislators should not be given credit EPA’s assertion that it Comment: Several commenters assert controlling effect, but when they are ‘‘appropriately concluded that it was that in the 1990 amendments to the consistent with the statutory language appropriate and necessary to regulate Clean Air Act, Congress directed the and other legislative history, they hazardous air pollutants * * * from EPA to base its determination regarding provide evidence of Congress’ intent.’’) EGUs’’ in 2000, and that it is today regulation of fossil-fuel-fired generating (emphasis added) (citation omitted); merely ‘‘confirm[ing] that finding and units on consideration of any adverse Garcia, et al., v. U.S., 469 U.S. 70, 78 conclud[ing] that it remains appropriate public health effects identified in the (1984), citing Zuber v. Allen, 396 U.S. and necessary to regulate these study mandated by the first sentence of 168, 187 (1969) (reiterating its prior emissions.* * *’’ 53 section 112(n)(1)(A) and that Congress findings, the Court indicated that Response: The commenter disagrees did not dictate in section 112(n)(1)(A) isolated statements ‘‘are ‘not impressive with certain statements in the preamble that the EPA must regulate electric legislative history.’ ’’); Weinberger, et al., to the proposed rule that provide that utility steam generating units under v. Rossi et al., 456 U.S. 25, 35 (declining the Agency’s interpretation of CAA section 112. to make a ruling based on ‘‘one isolated section 112(n)(1) is reasonable and According to the commenters the remark by a single Senator’’); Consumer consistent with the 2000 finding. It is sponsor of the House bill that became Product Safety Comm., et al. v. GTE difficult to decipher the exact complaint section 112(n)(1)(A) provides an Sylvania, Inc., et al., 447 U.S. 102, 117– that the commenter has with EPA’s explanation that contradicts the EPA’s 118 (1980) (declining to give much proposed rule in this regard, but the approach to regulating EGUs: weight to isolated remarks of one commenter does assert that ‘‘the Agency Representative); Chrysler Corp. v. did not provide in 2000 any Pursuant to section 112(n), the Brown, et al., 441 U.S. 281, 311 (1979) Administrator may regulate fossil fuel fired interpretation of what it now electric utility steam generating units only if (finding that ‘‘[t]he remarks of a single characterizes as the ‘‘critical terms’’ of the studies described in section 112(n) legislator, even the sponsor, are not CAA section 112(n)(1).’’ The clearly establish that emissions of any controlling in analyzing legislative commenter’s assertion lacks foundation. pollutant, or aggregate of pollutants, from history.’’); Zuber, 396 U.S. at 186 Although the 2000 finding did not such units cause a significant risk of serious (concluding that ‘‘[f]loor debates reflect provide detailed interpretations of the adverse effects on the public health. Thus, at best the understanding of individual regulatory terms at issue, it discussed * * * he may regulate only those units that Congressmen.’’); and U.S. v. O’Brien, the types of considerations relevant to he determines—after taking into account 391 U.S. 367, 384 (1968) (in evaluating the appropriate and necessary inquiry. compliance with all provisions of the act and the statements of a handful of For example, it is clear that in 2000, the any other Federal, State, or local regulation Congressmen, the Court concluded that and voluntary emission reductions—have Agency was concerned with the then been demonstrated to cause a significant ‘‘[w]hat motivates one legislator to make current hazards to public health and the threat of serious adverse effects on the public a speech about a statute is not environment when assessing whether it health. necessarily what motivates scores of was appropriate to regulate EGUs under others to enact it. * * *.’’). As these 136 Cong. Rec. H12,934 (daily ed. Oct. section 112.54 In addition, when cases show, the Supreme Court does not 26, 1990) (statement of Rep. Michael evaluating whether it was necessary to give weight to the statements of an Oxley). regulate utilities, the Agency stated that individual legislator, except when the it was necessary to regulate HAP The commenters stated that the EPA statements are supported by other emissions from U.S. EGUs under section position is premised on the assumption legislative history and the clear intent of 112 because the implementation of the that ‘‘regulation under section 112’’ the statute. The commenters cited no other requirements of the Act would not necessarily means ‘‘regulation under case law that would support reliance on 112(d)’’ and falsely premised on the such limited legislative history. 53 Id. at 24,977/3. assumption that source categories listed The commenter has not cited any 54 65 FR 79830. by operation of section 112(n)(1)(A) other legislative history to support

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Representative Oxley’s statement, and CAA section 112(n)(1), a provision that that its change of position is the lack of additional support makes the provides the Agency with considerable permissible. See 76 FR 24988/1 (‘‘[T]o statement of little utility or import discretion, and nothing indicates that the extent our interpretation differs from under the case law. In fact, there does others in the Senate (or for that matter that set forth in the 2005 Action, we not appear to be anything in the House, anyone else in the House) would agree explain the basis for that difference and Senate, or Committee Reports that with that interpretation. Given the why the interpretation, as set forth in supports Oxley’s statement. The lack of Supreme Court’s views on the use of this preamble, is reasonable.’’). In support for Oxley’s statement in the such limited legislative history, the EPA support, commenters note that the EPA Committee Report is particularly telling reasonably declined to consider (or even cites National Cable & since, as the commenter notes, the discuss) the legislative history in the Telecommunication Ass’n v. Brand X House and Senate bills required preamble to the proposed rule and we Internet Services, 545 U.S. 967 (2005). different approaches to regulating EGUs believe it would be improper to ascribe The commenters agree that it is true under section 112, with the Senate bill Representative Oxley’s statements to the that, in Brand X Internet Services, the requiring EGUs be regulated prior to the entire Congress. Supreme Court explained that, if an Utility Study. In fact, legislative Moreover, Representative Oxley’s agency ‘‘adequately explains the reasons statements from Senator Durenberger, a statement directly conflicts with the for a reversal of policy,’’ such change is supporter of the Senate version, statutory text. Representative Oxley ‘‘not invalidating,’’ since the ‘‘whole demonstrate that others would almost stated that ‘‘[the Administrator may point of Chevron is to leave the certainly not have agreed with Oxley’s regulate only those units that he discretion provided by the ambiguities interpretation. For example, Senator determines—after taking into account of a statute with the implementing Durenberger stated, ‘‘It seems to me compliance with all provisions of the agency.’’ 545 U.S. at 981 (internal inequitable to impose a regulatory act and any other Federal, State, or quotations omitted). The commenters regime on every industry in America local regulation and voluntary emission maintain that all Brand X Internet and then exempt one category, reductions—have been demonstrated to Services was saying is that ‘‘[a]gency especially a category like power plants cause a significant threat of serious inconsistency is not a basis for declining which are a significant part of the air adverse effects on the public health.’’ to analyze the agency’s interpretation toxics problem.’’ 136 Cong. Rec. H12934 (daily ed. Oct. under the Chevron framework.’’ Id. Senator Durenberger discussed the 26, 1990), reprinted in 1 1990 Legis. According to the commenter, it is not negotiations with the Administration Hist. at 1416–17 (emphasis added). enough that the EPA has purported to and the industry push to avoid However, the Utility Study required ‘‘explain’’ why it has abandoned the regulation, including industry under CAA section 112(n)(1)(A) directs interpretation of CAA section 112(n)(1) arguments for not regulating Hg from the Agency to consider the hazards to adopted in 2005. The commenter states U.S. EGUs: public health reasonably anticipated to that under the first step of Chevron, the occur after ‘‘imposition of the Agency’s latest interpretation must still The utility industry continued to requirements of [the Clean Air Act].’’ be consistent with congressional intent. adamantly oppose [regulation under section EPA was not required to consider state See Chevron v. NRDC, 467 U.S. at 842– 112]. First, they argued that mercury isn’t much of an environmental problem. But as or local regulations or voluntary 43. The commenters state that under the the evidence mounted over the summer and emission reduction programs in the second step of Chevron, if there is it became clear that mercury is a substantial Utility Study, and that study is the only discretion for EPA to exercise in threat to the health of our lakes, rivers and condition precedent to making the interpreting the ‘‘critical terms’’ of CAA estuaries and that power plants are among appropriate and necessary finding.55 section 112(n)(1), the Agency must the principal culprits, they changed their The legislative history the properly define the range of that tactic. Now they are arguing that mercury is commenters rely on is not controlling. discretion and then act reasonably in a global problem so severe that just cleaning The Agency believes that it has exercising that discretion. See Chevron, up U.S. power plants won’t make enough of reasonably interpreted section 467 U.S. at 843; see also Village of a difference to be worth it. They’ve gone from 112(n)(1)(A), for all the reasons Barrington, Ill. v. Surface ‘we’re not a problem’ to ‘you can’t regulate described herein and in the proposal. us until you address the whole global Transportation Bd., No. 09–1002 (D.C. problem.’ Recasting an issue that way is not The commenters also cite Cir. Mar. 15, 2011).The commenters new around here. So, it is not a surprise. But Representative Oxley’s statements as allege that the EPA failed to properly it does suggest the direction in which this support for alternative interpretations of define and exercise the scope of its debate will be heading in the next few years. CAA section 112(n)(1). We believe that discretion. In each instance, the any arguments that rely on such limited 136 Cong. Rec. 36062 (October 27, commenter maintains that the Agency legislative history are without merit. 1990). has departed from the correct Comment: One commenter stated that interpretation of CAA section 112(n)(1) Senator Durenberger also explained the EPA does acknowledge that, in that it adopted in 2005, seizing instead why the House version was adopted: many significant respects, its new upon a new approach that is contrary to Given that a resolution of the difficult interpretation of CAA section 112(n)(1) the plain language of the CAA itself, as issues in the conference were necessary to ‘‘differs from that set forth’’ in the interpreted after considering the conclude work on this bill, the Senate Agency’s 2005 rulemaking, but argues statements of Representative Oxley. proposed to recede to the House provision Response: The commenter appears to which was taken from the original 55 In addition, the EPA only considered CAA argue that the EPA’s interpretation of administration bill. It provides for a 3-year requirements in the Utility Study and this was the CAA section 112(n)(1) is not consistent study of utility emissions followed by correct approach because Congress knew how to require consideration of non-Federal requirements with the plain language of the statute, regulation to the extent that the implying that the statute is clear and Administrator finds them necessary. when directing EPA to conduct a study or assessment. See CAA section 112(n)(5) (Congress must be evaluated under step one of Id. required EPA to conduct an assessment of hydrogen Chevron. See Chevron v. NRDC, 467 sulfide from oil and gas extraction activities and Senator Durenberger’s statements provided that the assessment ‘‘shall include review U.S. 837 842–42 (1984) (finding that indicate that it is unlikely that he would of existing State and industry control standards, when the legislative intent is clear no agree with Oxley’s interpretation of techniques and enforcement.’’). additional analysis is required).

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However, as noted above, much of the generation, including modern coal-fired regulation’’ of HAP emissions is commenter’s argument that the plain generation.’’ Id. ‘‘appropriate and necessary’’ to address language of the statute precludes EPA’s The commenter stated that this the ‘‘hazards to public health’’ that may interpretation is based on the remarkably forthright statement be attributable to HAP emissions. unpersuasive legislative history establishes that the underlying basis for According to the commenter, by discussed above. As explained in the EPA’s proposal to regulate EGUs under contrast, in this rulemaking, the EPA preamble to the proposed rule, the CAA section 112 is not to address any has seized upon the fact that the control statute directs the Agency to determine ‘‘hazards to public health’’ that might be of EGU HAP emissions will also control whether it is appropriate and necessary attributed to the emission by EGUs of non-HAP (such as PM), and then seeks to regulate EGUs under section 112. As HAP listed under CAA section 112(b). to justify the regulation of HAP the D.C. Circuit has held, the terms Rather, according to commenter, the emissions based almost entirely on the ‘‘appropriate’’ and ‘‘necessary’’ are very EPA is utilizing the regulation of EGUs health benefits of the reductions in non- broad terms. Because these terms are under CAA section 112 as a means to an HAP emissions that would be entirely different end: To force the broad they are susceptible to different coincidentally achieved. The imposition of controls that will also interpretations. We believe we have commenter believes that this have the result of reducing non-HAP reasonably interpreted the appropriate ‘‘regulatory sleight-of-hand’’ runs afoul emissions (primarily PM) or force the and necessary language in section of congressional intent and is unlawful. 112(n)(1)(A). To the extent that shutdown of those units for which the interpretation differs from the one set cost of such controls would be Response: The commenter alleges that forth in 2005, we have fully explained prohibitive. At the same time, according the health-related benefits to regulating the basis for such changes. See 76 FR to commenter, the EPA tacitly HAP emissions from EGUs are 24986–24993 (setting forth the Agency’s acknowledges that it cannot hope to ‘‘questionable and miniscule,’’ and that interpretation of section 112(n)(1)). make out a case that the regulation of the only real benefits stem from non- Furthermore, we properly considered EGU HAP emissions is ‘‘appropriate and HAP emissions, such as PM. The the scope of our discretion in necessary’’ within the meaning of CAA commenter also implies that regulation interpreting the statute as explained in section 112(n)(1). The commenter of HAP is nothing more than a straw detail in the preamble to the proposed asserts that the only HAP whose health- man and that the Agency’s ultimate goal rule. We believe the interpretation set related benefits EPA quantifies is Hg. is to regulate other pollutants, and forth in the preamble to the proposed Elsewhere, the commenter stated that specifically PM. These allegations are rule is consistent with the Act and, the EPA contends there are ‘‘additional wholly without merit. The Agency has therefore, the Agency should be health and environmental effects’’ conducted comprehensive technical afforded deference pursuant to National attributable to HAP other than Hg, but analyses that confirm that HAP Cable & Telecommunication Ass’n v. admits that it has ‘‘not quantified’’ those emissions from EGUs pose a hazard to risks due supposedly to ‘‘insufficient Brand X Internet Services, 545 U.S. 967 public health. The analyses are information.’’ See 76 FR 24999/2. With (2005). discussed at length elsewhere in this respect to Hg the commenter stated that Comment: A number of commenters final rule, and a review of the proposed the benefits are so questionable and agreed with the Agency’s interpretation and final rules utterly refutes miniscule, some $4 million to $6 commenter’s assertion that PM of section 112(n)(1) and the terms million (given a 3 percent discount appropriate and necessary. The reductions form the basis for the rate), that compared to the total social appropriate and necessary finding. In commenters also agreed that the EPA’s costs of the rule (i.e., nearly $11 billion) interpretation of that provision was addition, the commenter appears to the rule cannot be justified were EPA ignore the Agency’s findings concerning reasonable and consistent with the properly to interpret CAA section statute. the hazards to public health and the 112(n)(1) and undertake the sort of environment posed by HAP emissions Response: We agree with the regulatory analysis Congress intended. simply because the Agency is not able commenters and appreciate their The commenter stated that the reason to quantify many of the benefits support. that the EPA touts in this rulemaking associated with reductions of HAP Comment: One commenter asserts the health benefits EPA attributes to the emissions from EGUs or because the that the EPA’s ultimate motivation for reduction of non-hazardous air rejecting its prior interpretation of CAA pollutants (again, primarily PM), the estimated HAP benefits that are section 112(n)(1) and embracing this regulation of which is authorized under quantified are small in relation to the flawed new approach is made clear from provisions of the CAA apart from CAA co-benefits achieved through reductions the very outset of the proposal. section 112, is to elide the inconvenient in non-HAP air pollutants, such as PM According to the commenter, the EPA truth regarding the truly trivial nature of and SO2, which are surrogates for touts the fact that ‘‘one consequence’’ of the benefits attributable to HAP certain HAP. The Agency is regulating the MACT rule would be that the regulation itself. The commenter EGUs pursuant to section 112(d) for all ‘‘market for electricity in the U.S. will concludes that the EPA distorts CAA of the reasons explained in the preamble be more level’’ and ‘‘no longer skewed section 112(n)(1)(A) ‘‘beyond all and discussed elsewhere in this in favor of the higher polluting units recognition.’’ response to comments. The commenter that were exempted from the CAA at its One commenter stated that the EPA is fails to recognize that the statute neither inception on Congress’ assumption that directed by CAA section 112(n)(1)(A) to requires a cost-benefit analysis prior to their useful life was near an end.’’ See study the ‘‘hazards to public health finding it appropriate and necessary to 76 FR 24979/2. The MACT rule would anticipated to occur as a result of regulate EGUs, nor requires such ‘‘require companies to make a emissions’’ by EGUs of ‘‘pollutants analysis prior to setting emission decision—control HAP emissions from listed under subsection (b) of this standards. Indeed, Congress expressly virtually uncontrolled sources’’ or else section’’—i.e., HAP and HAP alone. precluded consideration of costs when ‘‘retire these sometimes 60 year old Thereafter, the EPA is authorized to setting MACT floors. As explained units and shift their emphasis to more regulate EGU HAP emissions if, and below, the EPA does not believe that it efficient, cleaner modern methods of only if, they determine that ‘‘such is appropriate to consider costs when

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determining whether to regulate EGUs action, the EPA relegated to a footnote a significant risk of serious adverse risk under CAA section 112. the Oxley statement that commenter to the public health’’ confirms that plain Comment: One commenter stated that relies on so heavily even though the language. See Oxley Statement at 1416– the EPA has ignored the language and statement supported the interpretation 17. The commenter further stated that intent of CAA section 112(n)(1)(A), as we provided in that rule. We recognized nothing on the face of CAA section interpreted based on Representative then what the commenter fails to 112(n)(1)(A) indicates that Congress Oxley’s statements, and that the recognize now, which is that the Agency intended that the EPA should (or must) Agency’s interpretation of this provision cannot argue that the meaning of CAA take into account any additional violates step one of Chevron. Under section 112(n)(1)(A) is clear based on information that might be developed Chevron where the ‘‘intent of Congress the statements of one legislator. through the other studies mentioned in is clear,’’ that is the ‘‘end of the matter,’’ Furthermore, the Agency’s subparagraphs (n)(1)(B) and (C) (i.e., the for both the implementing agency and a interpretation does not violate Chevron Mercury Study 56 and the NAS reviewing court ‘‘must give effect to the Step 1. The terms ‘‘appropriate’’ and Study 57), such as HAP emissions from unambiguously expressed intent of ‘‘necessary’’ are ambiguous. The non-EGU sources. The commenter also Congress.’’ Chevron, 467 U.S. at 842–43. statements of a lone legislator do not identified other provisions of section The commenter asserts that the transform those ambiguous words into a 112 that specifically require legislative history of CAA section Chevron Step 1 situation. consideration of environmental effects 112(n)(1)(A) ‘‘sheds considerable light Moreover, the commenter’s assertion and states that Congress would have on Congress’ unique approach to that Congress unambiguously defined requires such consideration in CAA regulation of EGUs under CAA § 112.’’ the factors to consider in making the section 112(n)(1) if it had wanted EPA According to the commenter, on April 3, appropriate determination is without to consider environmental effects. 1990, the Senate passed S. 1630. The merit. We fully explain in the preamble The commenter makes a related Senate bill would have required EPA to to the proposed rule the basis for the assertion that the EPA acts contrary to list EGUs under CAA section 112(c) and Agency’s interpretation, and we are not congressional intent by assuming to regulate them under the MACT revising that interpretation based on the authority to assess the ‘‘‘hazard to provisions of CAA section 112(d). See S. comments received. public health or the environment [from] 1630 section 301, 3 1990 Legis. Hist. at Finally, the EPA notes that the HAP emissions from EGUs alone’ or the 4407. Thereafter, the House of sentence concerning regulation under ‘result of HAP emissions from EGUs in Representatives passed a modified CAA section 112(d) that the commenter conjunction with HAP emissions from version of S. 1630 on May 23, 1990. quotes from the preamble states, in full: other sources’’’ (citing 76 FR at 24,988/ This House version substantially ‘‘Congress did not exempt EGUs from 1). According to the commenter, the changed the provisions of CAA section the other requirements of section 112 only evident basis for the Agency’s 112 as they applied to EGUs. See 1 1990 and, once listed, the EPA is required to interpretation that, in making its Legis. Hist. at 572–73. The House establish emission standards for EGUs ‘‘appropriate and necessary’’ finding, version was virtually identical to the consistent with the requirements set the EPA can (and should) take into current CAA section 112(n)(1)(A), and forth in section 112(d), as described account HAP emissions from sources was ultimately adopted by the above.’’ 76 FR 24993 (emphasis added). other than EGUs, is that the Mercury conference committee, enacted by The EPA discusses requirements to Study authorized by CAA 112(n)(1)(B) Congress and signed into law. regulate section 112(c) listed sources references ‘‘mercury emissions from According to the commenter, Congress under section 112(d) in response to * * * municipal waste combustion expressly rejected the ‘‘list-under-(c)- other comments. units, and other sources, including area and-regulate-under-(d)’’ approach that c. Consideration of Both Environmental sources,’’ in addition to EGUs. The S. 1630 would have applied to EGUs, Effects and Health Effects From Other commenter asserts, however, that and that Congress did choose to apply Sources subparagraph (n)(1)(A) identifies the to other source categories. The Utility Study as the sole study to inform commenter stated that the EPA’s Comment: Several commenters stated EPA’s ‘‘appropriate and necessary’’ interpretation that the Agency is that the EPA acts contrary to finding. The commenter states that if ‘‘required to establish emission congressional intent when the Agency Congress had intended that the EPA standards for EGUs consistent with the considers itself ‘‘thereby authorized to take into account information developed requirements set forth in section 112(d)’’ consider ‘environmental effects’ and the through the Mercury Study, Congress (Id. at 24,993/3) fails to take the effects of HAP emissions from non-EGU ‘‘would not have specified that the EPA legislative history into account, and in sources, in making its ‘appropriate and was to predicate its ‘appropriate and a footnote, the commenter states that the necessary’ finding under subparagraph necessary’ finding on the ‘results of the Agency erred by not addressing the (n)(1)(A).’’ study required by this subparagraph’ legislative history as it did in the 2005 Commenters assert that the EPA (n)(1)(A).’’ action. misreads CAA section 112(n)(1)(B) and Commenter also cites to a number of Response: For the reasons stated (C) to inject environmental effects in the other section 112 provisions that above, we believe commenter’s reliance CAA section 112(n)(1)(A) expressly address environmental effects on the single statement of one legislator determination. According to one and the commenter states the only is flawed. In addition, in a footnote the commenter the plain language of CAA conclusion to draw from the inclusion commenter stated that the EPA section 112(n)(1) establishes that in those provisions and the absence of recognized ‘‘that it had to address’’ the regulation of EGUs is to be predicated such language in section 112(n)(1)(A) is legislative history in its 2005 action, and solely on ‘‘hazards to public health’’ that Congress intended public health to that the EPA erred in this case because attributable to HAP emissions. The be the only basis for the appropriate and we did not address the legislative legislative history providing that the necessary finding. history. The commenter cites no case EPA ‘‘may regulate [EGUs] only if the law to support its contention that an studies described in section 112(n) 56 U.S. EPA. 1997. Mercury Study Report to Agency must ‘‘address’’ unpersuasive clearly establish that emissions of any Congress. EPA–452/R–97–003. December. legislative history. Further, in the 2005 pollutant * * * from such units cause 57 NAS, 2000.

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Response: The commenter again relies and necessary finding in the context of purposes that are distinguishable from in part on the statements of one all three studies required under CAA CAA section 112(n)(1), and we do not legislator to attack EPA’s reasoned section 112(n)(1) because the provision believe one can reasonably draw the interpretation of an ambiguous statute. is title ‘‘Electric utility steam generating conclusion that the commenter does To the extent the commenter’s units.’’ 59 The commenter has provided when comparing those provisions to arguments rely on this limited evidence, little more than unpersuasive legislative CAA section 112(n)(1)(A). The lack of a we refer to the response above. As we history to support its restrictive requirement to consider environmental stated above, CAA section 112(n)(1) is interpretation of our authority. Id. effects in CAA section 112(n)(1)(A) does an ambiguous statutory provision; thus, The commenter also argues that the not equate to a prohibition on the the EPA’s interpretation, not statute clearly prohibits the Agency consideration of environmental effects commenter’s, is entitled to considerable from considering adverse environmental as the commenter concludes. The EPA deference if it is a reasonable reading of effects or the cumulative effects of HAP maintains that it reasonably concluded the statute. Chevron, 467 U.S. at 843–44. emissions from EGUs and other sources that we should protect against identified For the reasons described herein and in based on its claim that the statute is or potential adverse environmental the proposal, we believe that we have clear when one properly considers the effects absent clear direction to the reasonably interpreted the statutory legislative history. Again, the contrary. terms at issue here. The Agency directs commenter has provided no support for Concerning the consideration of the attention to section III.A. of the its contention other than the statements cumulative effect of HAP emissions proposed rule, which includes a of one Representative and the improper from EGUs and other sources, we thorough discussion of the Agency’s conflation of the CAA section provided a reasonable interpretation of interpretation of the relevant statutory 112(n)(1)(A) direction on the conduct of the statute and noted that our terms. To the extent the commenters the Utility Study and the appropriate interpretation, unlike commenters, does disagree with EPA’s interpretations, the and necessary finding. Congress left it to not ‘‘ignore the manner in which public EPA refers back to its discussion in the the Agency to determine whether it is health and the environment are affected proposal and responds to the comments appropriate and necessary to regulate by air pollution. An individual that as follows. EGUs under CAA section 112 and the suffers adverse health effects as the The commenter appears to maintain statute does not limit the Agency to result of the combined HAP emissions that the EPA must interpret the scope of considering only hazards to public from EGUs and other sources is harmed, the appropriate and necessary finding health and only harms directly and irrespective of whether HAP emissions solely in the context of the CAA section solely attributable to EGUs. from EGUs alone would cause the 112(n)(1)(A) Utility Study, such that The commenter stated that Congress harm.’’ 60 only hazards to public health and only specifically told EPA when it wanted d. Finding for All HAP To Be Regulated EGU HAP emissions may be considered. EPA to consider adverse environmental The commenter incorrectly conflates the effects in CAA section 112 and cites to Comment: Several commenters stated requirements for the Utility Study with several provisions of the Act that that for those EGU HAP for which the the requirement to regulate EGUs under require consideration of adverse Agency makes no CAA section CAA section 112 if EPA determines it is environmental effects. The commenter 112(n)(1)(A) determination, their appropriate and necessary to do so. The ignores CAA section 112(n)(1)(B), which regulation under CAA section 112 is not commenter concedes that the Agency directs the Agency to consider adverse authorized. For example, one may consider information other than environmental effect. In any event, even commenter maintains that the Agency that contained in the Utility Study, but were we to view section 112(n)(1)(A) in could regulate HAP emissions from only to the extent it relates specifically isolation, as the commenter suggests, we EGUs under CAA section 112(n). to hazards to public health directly still maintain that we can consider Accordingly, to the extent that the EPA attributable to HAP emissions from adverse environmental effects under reads CAA section 112, as construed by EGUs. We agree that we may consider 112(n)(1)(A). Nothing in section National Lime Ass’n, as compelling it to additional information other than that 112(n)(1)(A) precludes consideration of regulate all HAP emitted by EGUs, contained in the Utility Study, as we environmental effects. Congress should the Agency make an stated in the preamble to the proposed required the Agency to assess whether ‘‘appropriate and necessary’’ rule, because courts do not interpret it is appropriate and necessary to determination under CAA section phrases like ‘‘after considering the regulate EGUs under section 112. We 112(n)(1)(A) with respect to a single results of’’ in a manner that precludes believe that adverse environmental HAP (e.g., Hg), the EPA stands poised to the consideration of other information. effects can be considered in the commit a fundamental legal error that See United States v. United appropriate analysis. Congress will condemn the final rule on review. Technologies Corp., 985 F.2d 1148, 1158 specifically directed the Agency to Cf., e.g., PDK Laboratories, Inc., 362 (2nd Cir. 1993) (‘‘based upon’’ does not consider adverse environmental effects F.3d at 797–98; Holland v. Nat’l Mining mean ‘‘solely); 58 see also 76 FR 24988. when delisting source categories Ass’n, 309 F.3d at 817 (where an agency We further explained in the preamble to pursuant to section 112(c)(9), and thus applies a Court of Appeals the proposed rule that it was reasonable we believe it is reasonable to consider ‘‘interpretation * * * because it to interpret the scope of the appropriate such effects when determining whether believed that it had no choice’’ and that it is appropriate to regulate such units it ‘‘was effectively ‘coerced’ to do so,’’ 58 Several commenters have taken issue with our under section 112, especially given that then the agency ‘‘cannot be deemed to citation to United States v. United Technologies Congress did not limit our appropriate have exercised its reasoned judgment’’). Corp. because the language at issue in that case was Response: We do not agree with the ‘‘based upon’’ and the language of section and necessary inquiry to the Utility 112(n)(1)(A) is ‘‘after considering the results of.’’ Study. See CAA section 112(c)(9)(B)(ii). commenter’s assertion that Congress We believe that, if anything, ‘‘based upon’’ is more Moreover, the other provisions of intended EPA to regulate only those prescriptive than ‘‘after considering the results of’’ CAA section 112 that specifically EGU HAP emissions for which an such that the case supports the Agency’s interpretation that additional information other discuss environmental effects have appropriate and necessary finding is than the Utility Study may be considered in making the appropriate and necessary finding. 59 76 FR 24986–87. 60 76 FR 24988.

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made, and the commenter has cited no Indeed, the D.C. Circuit Court expressly ‘‘hazards to public health and the provision of the statute that states a noted that ‘‘where Congress wished to environmental are at issue (citing 76 FR contrary position. The EPA reasonably exempt EGUs from specific at 24989). ‘‘Two commenters stated that concluded that we must find it requirements of section 112, it said so a natural reading of the term ‘‘appropriate’’ to regulate EGUs under explicitly,’’ noting that ‘‘section ‘‘appropriate’’ would include the CAA section 112 if we determine that a 112(c)(6) expressly exempts EGUs from consideration of costs. According to the single HAP emitted from EGUs poses a the strict deadlines imposed on other commenters, something may be found to hazard to public health or the sources of certain pollutants.’’ Id. be ‘‘appropriate’’ where it is ‘‘specially environment. If we also find that Congress did not exempt EGUs from the suitable,’’ ‘‘fit,’’ or ‘‘proper.’’ See regulation is necessary, the Agency is other requirements of section 112, and Webster’s Third New International authorized to list EGUs pursuant to once listed, the EPA is reasonably Dictionary at 106 (1993). The term CAA section 112(c) because listing is regulating EGUs pursuant to the ‘‘appropriate’’ carries with it the the logical first step in regulating source standard-setting provisions in section connotation of something that is categories that satisfy the statutory 112(d), as it does for all other listed ‘‘suitable or proper in the criteria for listing under the statutory source categories. circumstances.’’ See New Oxford framework of CAA section 112. See New The commenter provided no American Dictionary (2d Ed. 2005). Jersey, 517 F.3d at 582 (stating that alternative theory for regulating EGUs Considering the costs associated with ‘‘[s]ection 112(n)(1) governs how the under CAA section 112, other than to undertaking a particular action is Administrator decides whether to list state that the EPA could regulate under inextricably linked with any EGUs. * * *’’). As we noted in the CAA section 112(n)(1). However, even determination as to whether that action preamble to the proposed rule, D.C. assuming for the sake of argument, that is ‘‘specially suitable’’ or ‘‘proper in the Circuit precedent requires the Agency to we could issue standards pursuant to circumstances.’’ One commenter notes regulate all HAP from major sources of CAA section 112(n)(1), we would that in 2005 (70 FR 15994, 16000; March HAP emissions once a source category decline to do because there is nothing 29, 2005) the EPA used the dictionary is added to the list of categories under in section 112(n)(1)(A) that provides any definition of ‘‘appropriate,’’ as being CAA section 112(c). National Lime guidance as to how such standards ‘‘especially suitable or compatible’’ and Ass’n v. EPA, 233 F.3d 625, 633 (D.C. should be developed. Any mechanism that it would be difficult to fathom how Cir. 2000). 76 FR 24989. we devised, absent explicit statutory a regulatory program could be either The commenter does not explain its support, would likely receive less ‘‘suitable’’ or ‘‘compatible’’ for a given issues with our interpretation of how deference than a CAA section 112(d) public health objective without regulation under section 112 works—i.e. standard issued in the same manner in consideration of cost. making a determination that a source which the Agency issues standards for One commenter asserts that on the category should be listed under CAA other listed source categories. We would face of CAA section 112(n)(1)(A), it is section 112(c), listing the source also decline to establish standards clear that the EPA is expected to category under CAA section 112(c), under section 112(n)(1) because consider costs. According to the regulating the source category under Congress did provide a mechanism commenter, that Congress intended that CAA section 112(d), and conducting the under CAA sections 112(d) and (f) for the EPA investigate and consider residual risk review for sources subject establishing emission standards for HAP ‘‘alternative control strategies’’ for to MACT standards pursuant to CAA emissions from stationary sources and it emissions as part of the section 112 section 112(f). Instead, it asserts that our is reasonable to use that mechanism to (n)(1) Utility Study when making the decision is flawed because the regulate HAP emissions from EGUs. ‘‘appropriate and necessary’’ interpretation we provided does not determination refutes the notion that the e. Considering Costs in Finding account for all the alternatives for Agency can, and indeed must, disregard regulating EGUs under section 112, and Comment: Several commenters assert the cost of regulation in making that that we have not properly exercised our that the EPA must consider costs in determination, because the cost of a discretion leading to a fatal flaw in our assessing whether regulation of EGUs is given emission ‘‘control strategy’’ is a rulemaking. appropriate under CAA section central factor in any evaluation of The commenter also ignores the 112(n)(1)(A). Commenters posit that the ‘‘alternative’’ controls. language of section 112(n)(1)(A). As EPA’s position that ‘‘the term Further, according to commenters, it explained in the proposed rule, the use ‘appropriate’ * * * does not allow for is well-settled that CAA regulatory of the terms section, subsection, and the consideration of costs in assessing provisions should be read with a subparagraph in section 112(n)(1)(A) whether hazards * * * are reasonably presumption in favor of considering demonstrates that Congress was anticipated to occur based on EGU costs (citing Michigan v. EPA, 213 F.3d consciously distinguishing the various emissions,’’ 76 FR at 24,989/1, does not 663, 678 (D.C. Cir. 2000)), and the provisions of section 112 in directing withstand scrutiny. According to the legislative history of section EPA’s action under section 112(n)(1)(A). commenters, the treatment of ‘‘costs’’ 112(n)(1)(A) confirms that Congress Congress directed the Agency to under section 112(c) does not support intended EPA to consider costs (citing regulate utilities ‘‘under this section,’’ the Agency’s position, and the process Oxley Statement at 1417). not ‘‘under this subparagraph,’’ and by which sources may be ‘‘delisted’’ Commenters also assert that the EPA accordingly EGUs should be regulated under section 112(c)(9), including no falsely represents that it ‘‘did not under section 112 in the same manner consideration of costs, sheds no light on consider costs when making the as other categories for which the statute the circumstances under which it may ‘‘appropriate’’ determination in the requires regulation. Furthermore, the be ‘‘appropriate’’ to regulate EGUs EPA’s December 2000 notice (76 FR at D.C. Circuit Court found that section under section 112(n)(1)(A). 24,989/2). 112(n)(1) ‘‘governs how the Commenters characterize as Response: The commenters first take Administrator decides whether to list ‘‘unintelligible’’ the EPA’s position that issue with EPA’s explanation of why the EGUs’’ and that once listed, EGUs are it is ‘‘reasonable to conclude that costs Agency determined that costs should subject to the requirements of section may not be considered in determining not be considered in making the 112. New Jersey, 517 F.3d at 583. whether to regulate EGUs’’ when appropriate determination. What

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commenters do not identify is an the environment from HAP emissions Congress in subparagraph 112(n)(1)(A) express statutory requirement that the from EGUs and Congress directed the to specify ‘‘after imposition of the Agency consider costs in making the Agency to regulate HAP emissions from requirements of Title IV of this appropriate determination. Congress EGUs under that provision if we make chapter,’’ but Congress did not. The treated the regulation of HAP emissions such a finding. Cost does not have to be commenters further add that the differently in the 1990 CAA read into the definition of ‘‘appropriate’’ legislative history confirms that amendments because the Agency was as commenter suggests. In addition, as Congress meant something much not acting quickly enough to address stated elsewhere in response to broader than that, providing that the these air pollutants with the potential to comments, the Agency does not EPA is authorized to regulate EGUs adversely affect human health and the consider costs in any listing or delisting under CAA section 112 only after environment. See New Jersey, 517 F.3d determinations, and the EPA maintains ‘‘taking into account compliance with at 578. Specifically, following the 1990 that it is reasonable to assess whether to all provisions of the act and any other CAA amendments, the CAA required list EGUs (i.e. the appropriate and Federal, State, or local regulation and the Agency to list source categories and necessary finding) without considering voluntary emission reductions.’’ The nothing in the statute required us to costs. commenters stated that the CAA’s consider costs in those listing decision, The commenters’ argument that costs ‘‘requirements’’ include the submission and we have not done so when listing must be considered based on the CAA by states of ozone and fine PM other source categories. Thus, it is section 112(n)(1)(A) requirement to attainment demonstrations, as well as reasonable to make the listing decision, ‘‘develop and describe alternative SIP provisions needed to reach including the appropriate control strategies’’ in the Utility Study attainment of the NAAQS because such determination, without considering is equally flawed. The argument is provisions could include controls on costs. flawed because Congress did not direct EGUs to reduce SO2 and NOX, which The commenters next argue that the the Agency to consider in the Utility controls could also result in a reduction Agency is compelled by the statute to Study the costs of the controls when in Hg emissions. consider costs based on a dictionary evaluating the alternative control Response: The commenter’s definition of ‘‘appropriate’’ and the CAA strategies. In addition, the EPA did not characterization of the facts is flawed section 112(n)(1)(A) direction to consider the costs of the alternative and its reliance on legislative history consider alternative control strategies controls in the Utility Study, as implied that is in direct conflict with the express for regulating HAP emissions in the by the commenter. Thus, even viewing terms of the statute is unpersuasive. Utility Study. section 112(n)(1)(A) in isolation, there is On the facts, the EPA explained in the Concerning the definition of nothing in that section that compels preamble to the proposed rule its ‘‘appropriate’’, commenters stated: EPA to consider costs. For the reasons interpretation of the phrase ‘‘after described herein, we do not believe that imposition of the requirements of [the Not only is it ‘‘reasonable’’ for EPA to consider costs in determining whether it is it is appropriate to consider costs in Act]’’ as it related to the conduct of the 61 ‘‘appropriate’’ to regulate EGU HAP determining whether to regulate EGUs Utility Study. We reasonably emissions, a natural reading of the term under section 112. concluded that, since Congress only indicates that excluding the consideration of Additionally, one commenter provided 3 years after enactment to costs would be entirely unreasonable. attempts to refute EPA’s statement in conduct the study, the phrase referred to Something may be found to be ‘‘appropriate’’ the preamble to the proposed rule that requirements that were directly imposed where it is ‘‘specially suitable,’’ ‘‘fit,’’ or the EPA did not consider costs in the on EGUs through the CAA amendments ‘‘proper.’’ See Webster’s Third New 2000 finding by pointing to the only two and for which the Agency could International Dictionary at 106 (1993). The term ‘‘appropriate’’ carries with it the mentions of cost in that notice. reasonably predict co-benefit HAP connotation of something that is ‘‘suitable or However, the EPA did not say that costs emission reductions. Id. The EPA did proper in the circumstances.’’ See New were not mentioned in the 2000 finding not state that the phrase only applied to Oxford American Dictionary (2d Ed. 2005) at and a review of the regulatory finding the Acid Rain program, as commenter 76. Considering the costs associated with will show that costs were not asserts, and the Utility Study in fact undertaking a particular action is considered in the regulatory finding. 65 discussed other regulations, including inextricably linked with any determination FR 79830 (December 20, 2000) (‘‘Section the NSPS for EGUs and revised NAAQS. as to whether that action is ‘‘specially III. What is EPA’s Regulatory With regard to the latter, the EPA suitable’’ or ‘‘proper in the circumstances.’’ Finding?’’). ultimately determined that it could not The EPA believes the definition of sufficiently quantify the reductions that f. Considering Requirements of the CAA ‘‘appropriate’’ that the commenters might be attributable to the NAAQS in ‘‘Necessary’’ provide wholly support its because states are tasked with interpretation and nothing about the Comment: Several commenters implementing those standards. See definition compels a consideration of disagree with EPA’s position that it Utility Study, pages ES–25, 1–3, 2–32. costs. It is appropriate to regulate EGUs need consider ‘‘only those requirements Conversely, commenter’s position is under CAA section 112 because EPA that Congress directly imposed on EGUs that the EPA must consider has determined that HAP emissions through the CAA as amended in 1990,’’ implementation of all the requirements from EGUs pose hazards to public for which ‘‘EPA could reasonably of the CAA, but it does not indicate how health and the environment, and section predict HAP emission reductions at the in conducting the Utility Study the 112 is ‘‘specially suitable’’ for regulating time of the Utility Study.’’ According to Agency could have possibly considered HAP emissions, and Congress the commenters, the statutory language co-benefit HAP reductions attributable specifically designated CAA section 112 of CAA section 112(n)(1) requires that to all future CAA requirements. The as the ‘‘proper’’ authority for regulating the EPA consider the scope and effect of Agency appropriately considered the HAP emissions from stationary sources, EGU HAP emissions after the other requirements of the Act in the including EGUs. Section 112 of the CAA imposition of all of the ‘‘requirements’’ Utility Study and considered those is ‘‘suitable [and] proper in the of the CAA, not just the Acid Rain requirements in determining that it was circumstances’’ because EPA has program. The commenter maintains that identified a hazard to public health and it would have been easy enough for 61 76 FR 24990.

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necessary to regulate coal- and oil-fired suggested that interpretation and a fair ‘‘necessary’’.) 76 FR 24990–92 (Section EGUs in December 2000. reading of the proposed rule will III.A.2.b of the proposed rule contains Although not required, the Agency in demonstrate that EPA considered EPA’s interpretation of the term the preamble to the proposed rule requirements that achieve co-benefit ‘‘necessary’’.) The commenter also, in a conducted further analyses in support of HAP emission reductions, for example footnote, implies that EPA based the the 2000 finding. In doing so, we the Transport Rule (known as CSAPR). appropriate and necessary finding on considered a number of requirements Comment: One commenter stated that, non-HAP air pollution. The commenter that far exceed what Congress under CAA section 112, regulating is wrong as explained in more detail contemplated when enacting CAA EGUs is permissible only insofar as it is above. section 112(n)(1)(A)), and our analyses focused, targeted, and predicated on As an initial matter, this comment is still show that it remains necessary to concrete findings by the Agency that only addressing one aspect of the regulate coal- and oil-fired EGUs under such regulation is indeed ‘‘necessary.’’ Agency’s interpretation of the term section 112. 76 FR 24991. According to the commenter, the EPA necessary. As EPA stated at proposal: We maintain that we have reasonably construes CAA section 112(n)(1)(A) as If we determine that the imposition of the interpreted the requirement to consider permitting it to find that it is requirements of the CAA will not address the the hazards to public health and the ‘‘necessary’’ to regulate EGUs even identified hazards, EPA must find it environment reasonably anticipated to where the Agency does not actually necessary to regulate EGUs under section occur after imposition of the know whether it is ‘‘necessary’’ to 112. Section 112 is the authority Congress requirements of the Act as explained in regulate EGUs. Citing the D.C. Circuit, provided to address hazards to public health the preamble to the proposed rule.62 In the EPA suggests that ‘‘‘there are many and the environment posed by HAP addition, as stated above, we also situations in which the use of the word emissions and section 112(n)(1)(A) requires believe it would be reasonable to find it ‘necessary,’ in context, means the Agency to regulate under section 112 if necessary to regulate HAP emissions something that is done, regardless of we find regulation is ‘‘appropriate and necessary.’’ If we conclude that HAP from EGUs based on our finding that whether it is indispensible,’’’ in order to emissions from EGUs pose a hazard today, such emissions pose a hazard to public ‘‘‘achieve a particular end.’’’ 76 FR such that it is appropriate, and we further health and the environment today 24990, quoting Cellular conclude based on our scientific and without considering future reductions Telecommunications v. FCC, 330 F.3d technical expertise that the identified that we currently project to occur as the 502, 510 (D.C. Cir. 2003). The hazards will not be resolved through result of imposition of CAA commenter stated that in the ‘‘context’’ imposition of the requirements of the CAA, requirements that are not yet effective of CAA section 112(n)(1)(A), as we believe there is no justification in the (e.g., CSAPR). informed by the relevant legislative statute to conclude that it is not necessary to Moreover, Representative Oxley’s history from Representative Oxley, it is regulate EGUs under section 112. statement cited by the commenter is not clear that regulation of EGU HAP 76 FR 24991. consistent with the express terms of emissions can be considered The EPA has determined that the CAA section 112(n)(1)(A) on this issue. ‘‘necessary’’ only if EPA were to imposition of the requirements of the Representative Oxley stated that the ‘‘clearly establish’’ that such regulation CAA will not address the hazards to EPA was to take ‘‘into account was effectively ‘‘indispensible’’ to public health or hazards to the compliance with all the provisions of address the identified harm. As EPA environment that EPA has identified; the act and any other Federal, State, or concedes that it has made no such therefore, it is necessary to regulate local regulation and voluntary emission determination here, its proposal is EGUs under CAA section 112. reductions,’’ but CAA section fatally flawed for that reason alone. The EPA further interpreted the 112(n)(1)(A) directs the Agency to The commenter further asserts that statute to allow the Agency to find that consider ‘‘imposition of the the EPA erred when it concluded that it it is necessary to regulate EGUs under requirements of this chapter,’’ which may ‘‘ ‘determine it is necessary to other circumstances, and it is with one means the CAA. The Agency reasonably regulate under section 112’ when the of our additional interpretations that focused on the requirements of the Agency is ‘uncertain whether commenter takes issue. Specifically, the Clean Air Act, which are federally imposition of the requirements of the commenter argues that EPA’s enforceable, and declined to include CAA will address the identified interpretation authorizes the Agency to potential future reductions that may be hazards’’’ (citing 76 FR at 24,991/3). find it necessary to regulate EGUs when attributable to voluntary emission According to the commenter, the EPA we are uncertain it is necessary, but that reduction programs or state and local ‘‘cannot take refuge in its own misconstrues our interpretation and the regulations that have no basis in the ‘uncertainty’ to support a finding that it record. At proposal, the EPA stated: Clean Air Act and are not federally is ‘necessary’ to regulate EGUs under enforceable. In addition to the statutory section 112, and the Act precludes the In addition, we may determine it is direction not to consider such necessary to regulate under section 112 even EPA from ‘‘‘err[ing] on the side of if we are uncertain whether the imposition of requirements, the EPA believes it is regulation’’’ in face of uncertainty (id.). the requirements of the CAA will address the reasonable not to include potential The commenter also implies that the identified hazards. Congress left it to EPA to reductions attributable to such finding was based on non-HAP determine whether regulation of EGUs under requirements because the Agency emissions. section 112 is necessary. We believe it is cannot assure that such requirements Response: The commenter again relies reasonable to err on the side of regulation of and the attendant HAP reductions will on the legislative statements of one such highly toxic pollutants in the face of remain absent regulation under section Representative and asserts that the uncertainty. Further, if we are unsure 112. Finally, the commenter implies statements are controlling. The EPA whether the other requirements of the CAA that EPA’s position is that the Agency disagrees with commenter and will address an identified hazard, it is reasonable to exercise our discretion in a will only consider requirements of the maintains that its interpretation of the manner that assures adequate protection of Act that directly regulate HAP term ‘‘necessary’’ is reasonable. 76 FR public health and the environment. emissions. The EPA never stated or 24990–92 (Section III.A.2.b of the Moreover, we must be particularly mindful of preamble to the proposed rule contains CAA regulations we include in our modeled 62 76 FR 24990. the EPA’s interpretation of the term estimates of future emissions if they are not

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final or are still subject to judicial review Furthermore, as we stated in the ‘‘required to establish emission ([e.g.], the Transport Rule). If such rules are preamble to the proposed rule, we standards for EGUs consistent with the either not finalized or upheld by the Courts, believe it would be reasonable to find it requirements set forth in section the level of risk would potentially increase. appropriate and necessary to regulate 112(d).’’ Id. at 24,993/3 (emphasis Id. EGUs under section 112 today based on added). The CAA requires EPA to exercise its a determination that HAP emissions The commenter stated that, in support discretion in determining whether from EGUs pose a hazard to public of this reading of the CAA, the EPA regulation under section 112 is health and the environment without invokes the decision of the U.S. Court necessary, and the D.C. Circuit has considering future HAP emission of Appeals for the D.C. Circuit in New stated that ‘‘there are many situations in reductions. 76 FR 24991, n.14. We Jersey v. EPA, 517 F.3d 574 (D.C. Cir. which the use of the word ‘necessary,’ maintain this is reasonable because 2008). The commenter further alleged in context, means something that is ‘‘Congress could not have contemplated that, according to EPA, the D.C. Circuit done, regardless of whether it is in 1990 that EPA would have failed in has ‘‘already held that section 112(n)(1) indispensible, to achieve a particular 2011 to have regulated HAP emissions ‘governs how the Administrator decides end.’’ See Cellular Telecommunications from EGU’s where hazards to public whether to list EGUs.’ ’’ See 76 FR & Internet Association, et al. v. FCC, 330 health and the environment remain.’’ Id. 24993/2–3, quoting 517 F.3d at 583. The F.3d 502, 510 (D.C. Cir. 2003). The The phrase ‘‘after imposition of the commenter stated that EPA construes EPA’s interpretation of ‘‘necessary’’ is requirements of [the Act]’’ as that holding as indicating that, ‘‘once reasonable in the context of CAA contemplated CAA section 112(n)(1)(A) listed, EGUs are subject to the section 112(n)(1)(A). could be read to apply only to those requirements of section 112’’— The commenter stated that EPA requirements clearly and directly including, the EPA presumes, CAA concedes that the Agency has not applicable to EGUs under the 1990 CAA section 112(d). Id. The commenter ‘‘clearly established’’ that regulation of amendments, all of which have been stated that elsewhere, the EPA construes HAP emissions under CAA section 112 implemented and still hazards to public CAA section 112(n)(1) (A) as is ‘‘indispensible.’’ The EPA has health and the environment from HAP ‘‘govern[ing] how the Administrator conceded nothing but, more emissions from EGUs remain. decides whether to list EGUs for importantly, the supposed standard that regulation under section 112,’’ and the commenter presents for evaluating g. Listing EGUs Under 112 quotes the D.C. Circuit’s observation in whether it is necessary to regulate HAP Comment: One commenter stated that New Jersey that ‘‘Section 112(n)(1) emissions from EGUs is not required by even if EPA were to establish under governs how the Administrator decides the statute. Even the limited legislative CAA section 112(n)(1)(A) that it is whether to list EGUs; it says nothing history on which the commenter ‘‘appropriate and necessary’’ to regulate about delisting EGUs.’’ See 76 FR incorrectly relies does not espouse such HAP emissions from EGUs, regulating 24981/2, quoting 517 F.2d at 582. a standard. The commenter specifically those emissions in the form of a MACT The commenter asserts that EPA takes issue with EPA’s statement that standard established pursuant to CAA misinterprets the ‘‘under this section’’ the Agency may find it is necessary to section 112(d) is contrary to the plain language of CAA section 112(n)(1); regulate EGUs under CAA section 112 if language of the Act. According to the overstates the significance of the New we are ‘‘uncertain whether imposition commenter, if EPA proceeds to finalize Jersey decision; and, as a consequence, of the other requirements of the CAA the proposal and adopts such a misapprehends the scope of its own will sufficiently address the identified standard, the rule will for this reason discretion to formulate regulatory hazards.’’ 76 FR at 24990. The alone be ‘‘dead-on-arrival’’. According standards for EGUs under CAA section commenter has again misinterpreted the to the commenter, the EPA apparently 112. In light of these errors, the Agency’s position by stating that ‘‘EPA believes that its only option in commenter maintains that EPA should construes CAA section 112(n)(1)(A) as regulating EGU HAP emissions is withdraw the proposed MACT rule. permitting it to find that it is establishing a MACT standard under One commenter stated that if ‘‘necessary’’ to regulate EGUs even CAA section 112(d). In the preamble to Congress had intended that EPA where the Agency does not actually its proposal, the commenter states that regulate EGU HAP emissions only know whether it is ‘‘necessary’’ to EPA contends that, ‘‘once the through a MACT standard, Congress regulate EGUs.’’ Instead, the EPA appropriate and necessary finding is could have—and presumably would maintains that it may be necessary to made,’’ EGUs are then ‘‘subject to have—directed the Agency to regulate regulate EGUs under CAA section 112 if section 112 in the same manner as other EGU emissions ‘‘under CAA section we identify a hazard to public health or sources of HAP emissions’’—i.e., by 112(d).’’ Thus, the commenter the environment that is appropriate to ‘‘listing’’ EGUs under CAA section maintained that EPA’s authority to regulate today and our projections into 112(c) and adopting a MACT standard regulate EGU HAP emissions is not the future do not clearly establish that under CAA section 112(d). See 76 FR derived from any particular subsection the imposition of the requirements of 24993/2 (emphasis added). The of CAA section 112. Rather, the the CAA will address the identified commenter further stated that, given commenter stated that EPA is hazard in the future. Making a that Congress ‘‘directed the Agency to authorized to regulate ‘‘under this prediction about future emission regulate utilities ‘under this section’ section’’—i.e., CAA section 112 reductions from a source category is [i.e., CAA section 112],’’ EPA continues, generally—as may be ‘‘appropriate and difficult for statutory provisions that do it follows that ‘‘EGUs should be necessary.’’ The commenter stated that not mandate direct control of the given regulated in the same manner as other there is nothing on the face of CAA source category or pollutants of concern. categories for which the statute requires section 112(n)(1)(A) that specifies that We maintain that erring on the side of regulation.’’ Id. (emphasis added). The regulation of EGUs must occur under caution is appropriate when the commenter asserts that as EPA sees it, CAA section 112(d). To the contrary, protection of public health and the because ‘‘Congress did not exempt EGUs according to the commenter, a plain environment from HAP emissions is not from the other requirements of section reading of CAA section 112(n)(1)(A), as assured based on our modeling of future 112,’’ once EGUs were ‘‘listed’’ under interpreted based on the Oxley emissions. CAA section 112(c), the Agency was statement, indicates that establishing a

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MACT standard for EGUs under CAA words, and the commenter’s to the coastal waters of the States which section 112(d) is not what Congress had interpretation does not give any are subject to [section 328 of the CAA].’’ in mind at all. particular meaning to the requirement to (emphasis added). Response: We do not agree with the ‘‘regulate under this section [112]’’. The In addition, CAA section 112(n)(3) commenter. The EPA interpreted CAA commenter is correct that Congress provides that when the Agency is section 112(n)(1)(A) in a manner that could have in CAA section 112(n)(1)(A) ‘‘promulgating any standard under this gives meaning to all the words used in directed EPA to regulate HAP from section [112] applicable to publicly the provision. See NRDC v. EPA, 489 EGUs under CAA section 112(d) after owned treatment works, the F.3d 1364, 1373 (D.C. Cir. 2007) making the appropriate and necessary Administrator may provide for control (admonishing EPA for an interpretation finding, but the commenter presumes measures that include pretreatment of of CAA section 112(c)(9) that ignored too much when it stated that Congress discharges causing emissions of certain words and the context in which would have directed the Agency to hazardous air pollutants and process or they were used. The Court stated that regulate HAP emissions from EGUs in product substitutions or limitations that ‘‘EPA’s interpretation would make the such a manner if that is what Congress may be effective in reducing such words redundant and one of them ‘mere wanted, simply by including the phrase emissions.’’ Finally, CAA section surplusage,’ which is inconsistent with ‘‘regulate under this paragraph’’ or 112(n)(5) directs the Agency to assess a court’s duty to give meaning to each ‘‘regulate under this subparagraph’’ hydrogen sulfide emissions from oil and word used by Congress.’’) (citing TRW instead of directing the Agency to gas extraction and ‘‘develop and Inc. v. Andrews, 534 U.S. 19, 31, 122 S. ‘‘regulate under this section’’. It did not implement a control strategy for Ct. 441, 151 L. Ed. 2d 339 (2001)). do so. emissions of hydrogen sulfide to protect Specifically, in the preamble to the As we explained in the section II.A. human health and the environment proposed rule, we stated: of the proposed rule, CAA section 112 *** using authorities under [the CAA] establishes a mechanism to list and The statute directs the Agency to regulate including [section 111] of this title and EGUs under section 112 if the Agency finds regulate stationary sources of HAP this section [112].’’ (emphasis added). such regulation is appropriate and necessary. emissions. 76 FR 24980–81. Regulation We believe these provisions provide Once the appropriate and necessary finding under CAA section 112 generally ample evidence that Congress knew is made, EGUs are subject to section 112 in requires listing under CAA section how to alter or caveat regulation under the same manner as other sources of HAP 112(c), regulation under CAA section emissions. Section 112(n)(1)(A) provision CAA section 112 when that was its 112(d), and, for sources subjected to intent. For these reasons, we believe provides, in part, that: ‘[t]he Administrator MACT standards, residual risk commenter’s argument is without merit. shall perform a study of the hazards to public regulations under CAA section 112(f) (as health reasonably anticipated to occur as a necessary to protect human health and Comment: Two commenters stated result of emissions by electric utility steam that CAA section 112(n)(1)(A) does not generating units of pollutants listed under the environment with an ample margin of safety). A determination that EGUs specify that regulation of EGUs must subsection (b) of this section after imposition proceed under CAA section 112(d). of the requirements of this chapter. * * * should be listed once the prerequisite The Administrator shall regulate electric appropriate and necessary finding is According to the commenter, an utility steam generating units under this made is wholly consistent with the argument could be made, therefore, that section, if the Administrator finds such language of section 112(n)(1)(A), and the CAA accords EPA with the regulation is appropriate and necessary after listed sources must be regulated under discretion to regulate EGUs using considering the results of the study required strategies other than emission standards by this subparagraph.’’ Emphasis added. CAA section 112(d). See CAA section 112(c)(2); see also New Jersey, 517 F.3d in CAA section 112(d). The commenters In the first sentence, Congress at 583 (112(n)(1)(A) ‘‘governs how the also state that section 112(n)(1)(A) of the described the study and directed the Administrator decides whether to list CAA requires that EPA ‘‘develop and Agency to evaluate the hazards to public EGUs’’). describe’’ alternative control strategies health posed by HAP emissions listed As noted above, Congress used the for emissions which may warrant under subsection (b) (i.e., CAA section terms section, subsection, and regulation under CAA section 112. 112(b)). The last sentence requires the subparagraph in section 112(n)(1)(A). According to the commenters if Agency to regulate under this section The use of these three terms Congress meant for EPA to have one (i.e., CAA section 112) if the Agency demonstrates that Congress was sole regulatory option, i.e., regulation of finds such regulation is appropriate and consciously distinguishing between the EGUs only under CAA section 112(d), necessary after considering the results of various provisions of section 112. then the development of alternative the study required by this subparagraph Congress directed the Agency to control strategies would be rendered (i.e., CAA section 112(n)(1)(A)). The use regulate utilities ‘‘under this section,’’ meaningless because under CAA section of the terms ‘‘section’’, ‘‘subsection’’, and accordingly EGUs should be 112(d)(3), the EPA is required to and ‘‘subparagraph’’ demonstrates that regulated in the same manner as other determine the level of control that is Congress was consciously categories for which the statute requires achieved by the best performing existing distinguishing the various provisions of regulation. units for which it has data and then to CAA section 112 in directing the Furthermore, the flaws in the impose that level of control on all conduct of the study and the manner in commenter’s interpretation are existing units. The commenter further which the Agency must regulate EGUs highlighted by other CAA section 112 states that the development of if the Agency finds it appropriate and provisions wherein Congress provided ‘‘alternative control strategies’’ has no necessary to do so. Congress directed specific direction as to the manner of role to play in this process. One the Agency to regulate utilities ‘‘under regulation. For example, CAA section commenter does note that the this section,’’ and accordingly EGUs 112(m)(6) requires the Administrator to consideration of ‘‘alternative’’ controls should be regulated in the same manner determine ‘‘whether the other becomes relevant, if at all, only in those as other categories for which the statute provisions of this section [112] are circumstances where EPA might seek to requires regulation. See 76 FR 24993. adequate’’ and also indicates that ‘‘[a]ny establish a ‘‘Beyond-the-Floor’’ MACT We maintain that our interpretation of requirements promulgated pursuant to standard pursuant to CAA section the statute gives meaning to all the this paragraph * * * shall only apply 112(d)(2).

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Response: The commenters are correct with the standards using any provisions of CAA section 112 in that CAA section 112(n)(1)(A) directed mechanism available, including pre- directing the conduct of the study and the Agency to develop and describe in combustion and post-combustion the manner in which the Agency must the Utility Study report to Congress measures. Also, the establishment of a regulate EGUs,’’ were the EPA to ‘‘find[ ] alternative control strategies for HAP MACT standard under CAA section it appropriate and necessary to do so.’’ emissions from EGUs that may warrant 112(d)(2) and (3) is a two-step process. See 76 FR 24993/2. According to the regulation in the Utility Study, but the In the first step, the Agency establishes commenter, the only evident reason that commenters’ interpretation of and a floor based on the performance of the the word ‘‘subsection’’ is used in the conclusion based on that language are best controlled unit or units. See CAA first sentence of CAA section both factually and legally inaccurate. section 112(d)(3). In the second step, the 112(n)(1)(A) is because the reference is The commenters appear to interpret Agency must consider additional made to the ‘‘pollutants’’ which the the word ‘‘alternative control strategies’’ measures that may reduce HAP Utility Study is to address—i.e., the to mean something other than the emissions and adopt such measures if ‘‘pollutants’’ that are emitted by EGUs traditional control technologies and reasonable after considering costs and and which are ‘‘listed under subsection control measures that are used to non-air quality health and (b)’’ of CAA section 112. Similarly, the control HAP emissions from EGUs. We environmental effects. See CAA section word ‘‘subparagraph’’ is used in the last do not believe that is a reasonable 112(d)(2). Under the second step, the sentence of CAA section 112(n)(1)(A) to interpretation of the statute, and the Agency can consider any measure that identify ‘‘the study’’ which the EPA is Agency did not interpret the statute in reduces HAP emissions even if no directed to undertake by subparagraph that manner when it conducted the source in the category is employing the (A) of CAA section 112(n)(1)—i.e., the Utility Study. In Chapter 13 of the option under consideration. So, even Utility Study. That the last sentence of Utility Study, the EPA considered a under the commenter’s flawed subparagraph (n)(1)(A) also states that range of control measures that would interpretation of ‘‘alternative control EPA ‘‘shall regulate electric utility reduce the different types of HAP strategies’’, the direction in CAA section steam generating units under this emitted from EGUs. http:// 112(n)(1)(A) is not a ‘‘pointless section’’ does not even imply—much www.epa.gov/ttn/atw/combust/utiltox/ exercise’’ for the development of CAA less expressly communicate—that eurtc1.pdf. The EPA considered pre- section 112(d) standards as the Agency regulation ‘‘under this section’’ must combustion controls such as coal considers relevant technologies and mean ‘‘regulation under section 112(d).’’ washing, fuel switching, and HAP emission reduction approaches in The commenter stated that Congress gasification; combustion controls such evaluating whether to set a more was ‘‘consciously distinguishing’’ as boiler design; post-combustion stringent beyond the floor standard. between the ‘‘various provisions of controls such as fabric filters, scrubbers, Comment: One commenter points to section 112’’ for the sake of clarity in the and carbon absorption; and alternative CAA section 307(d)(1)(C) and notes that drafting of CAA section 112(n). controls strategies such as demand-side CAA section 112(n) is listed among the The commenter also asserts that the management, energy conservation, and provision for which the rulemaking EPA mistakenly relies on section use of alternative fuels (e.g., biomass) or requirements of CAA 307(d) apply. 112(c)(6) when the EPA states that renewable energy. The options Commenter maintains that this ‘‘ ‘where Congress wished to exempt discussed in the Utility Study for inclusion creates an expectation under EGUs from specific requirements of controlling HAP emissions from EGUs the statute that EPA may establish section 112, it said so explicitly. are almost universally available to regulatory standards under CAA 112(n). Congress did not exempt EGUs from the comply with a CAA section 112(d) The commenter points to CAA sections other requirements of section 112,’ ’’ and standard. 112 (n)(1), (n)(3), and (n)(5) and states thus the Agency is ‘‘ ‘required to Given the manner in which the that those provisions specifically establish emission standards for EGUs Agency conducted the Utility Study, the discuss regulation under CAA section consistent with the requirements set EPA interpreted the statutory direction 112 and that EPA must explain why forth in section 112(d)’ ’’ (citing 76 FR as a requirement to set forth the CAA 307(d)(1)(C) states ‘‘any regulation at 24,993 (internal quotation omitted)). potential alternative control options under’’ CAA 112(n) to defend regulation According to the commenter, nothing available to EGUs to comply with CAA of utilities under section 112(d). The in section 112(c)(6) indicates how (or section 112 standards in the event the commenter then implies that EPA erred even whether) EGU HAP emissions Agency determined regulation under by not even mentioning this provision at should be regulated under section 112; section 112 was appropriate and proposal. paragraph (c)(6) serves only to reiterate necessary. The EPA’s development and The commenter also takes issue with that the regulation of such emissions is discussion in the Utility Study of EPA’s statement in the proposed rule to occur (if at all) as is provided by alternative control strategies for that ‘‘use of the terms section, section 112(n)(1). The commenter also complying with the standards would subsection, and subparagraph’’ asserts that the EPA mistakenly relies on help prepare EGUs to comply with the ‘‘demonstrates that Congress was New Jersey. According to the standards if promulgated. Thus, the EPA consciously distinguishing the various commenter, the D.C. Circuit in that case interpreted the direction to address provisions of section 112 in directing did not indicate that the language of control strategies in the Utility Study as the conduct of the study and the manner section 112(c)(6) should, or could, be a request to identify the controls in which the Agency must regulate construed to mean that EGUs must be available to EGUs for addressing HAP EGUs,’’ if EPA determines that it is regulated under a MACT standard emissions, and such information would, appropriate and necessary to regulate adopted pursuant to section 112(d). of course, be relevant if EPA determined EGUs. See 76 FR at 24,993/2. Response: The commenter makes a that such emissions warranted One commenter does not agree with number of arguments that appear to take regulation under section 112. the EPA’s finding that the word issue with the EPA’s determination that Furthermore, the EPA establishes ‘‘subsection’’ in the first sentence of EGUs should be regulated under CAA CAA section 112(d) standards for CAA section 112(n)(1)(A) demonstrates section 112(d) if the Agency determines stationary sources and it is the that Congress was consciously that regulation of HAP emissions from responsibility of the sources to comply distinguishing between the various such units is appropriate and necessary.

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The commenter implies that the EPA 112(n)(1) were available to regulate ‘‘where Congress wished to exempt EGUs erred because alternative mechanisms EGUs, there would be sufficient from specific requirements of section 112, it for regulation of EGUs under CAA uncertainty about the legal vulnerability said so explicitly,’’ noting that ‘‘section section 112 might exist. We do not of such an approach to caution against 112(c)(6) expressly exempts EGUs from the strict deadlines imposed on other sources of agree. employing it. This legal uncertainty certain pollutants.’’ Id. Congress did not The commenter’s argument that the would be particularly troubling in light exempt EGUs from the other requirements of EPA erred because we did not explain of the fact that we have identified CAA section 112, and once listed, EPA is why section CAA section 307(d)(1)(C) hazards to public health and the required to establish emission standards for contemplates regulations under CAA environment from HAP emissions from EGUs consistent with the requirements set section 112(n) is without merit. It is EGUs that warrant regulation, and these forth in CAA section 112(d), as described correct that the Agency believes EGUs regulations are long overdue. below. See 76 FR 24993. should be regulated in the same manner The commenter also takes issue with As can be seen from this passage, the as other sources if the appropriate and our statement in the preamble to the Court cited section 112(c)(6) as an necessary finding is made because of the proposed rule that the use of the words example of Congress’ intent regarding structure of CAA section 112. Nothing ‘‘section’’, ‘‘subsection’’, and regulating EGUs under CAA section in CAA section 112(n)(1) requires or ‘‘subparagraph’’ in CAA section 112. The commenter cited the last implies that the Agency should or must 112(n)(1)(A) ‘‘demonstrates that clause of the last sentence of the establish standards for EGUs under that Congress was consciously paragraph quoted above without provision. Furthermore, unlike CAA distinguishing the various provisions of including the prefatory clause ‘‘once sections 112(n)(3) and 112(n)(5) that section 112 in directing the conduct of listed,’’ and, without that clause, the commenter cites, CAA section the study and the manner in which the statement is not fairly characterized. 112(n)(1)(A) does not provide any Agency must regulate EGUs.’’ See 76 FR The point the EPA was making in that guidance concerning the manner in 24993. The commenter appears to make paragraph is that EGUs are a listed which EPA is authorized or required to much of our use of the word ‘‘must’’ in source category and listed sources must regulate sources under CAA section 112. that sentence and also states that our be regulated under CAA section 112(d) See CAA section 112(n)(3) (specifically interpretation of the significance of the unless the EPA delists the source authorizing identified control measures use of the three terms in CAA section category. and other requirements for 112(n)(1)(A) is flawed because Congress Comment: One commenter stated that consideration in issuing standards only used the three terms for purposes EPA overstates the significance of the under CAA section 112); see also CAA of clarity. The commenter is incorrect D.C. Circuit’s holding in New Jersey by section 112(n)(5) (directing the Agency on both points. With respect to the suggesting that the decision mandates to develop and implement a control commenter’s concern regarding the use EGU regulation under CAA section strategy for emissions of hydrogen of the word ‘‘must’’ in the sentence 112(d) because EGUs ‘‘remain listed’’ sulfide using any authority available quoted above, we note that in the next under CAA section 112(c), See New under the CAA, including sections 112 sentence we stated that ‘‘Congress Jersey, 517 F.3d at 582. According to the and 111, if regulation is appropriate). directed the Agency to regulate utilities commenter, the court declined to For these reasons, we disagree that any ‘under this section,’ and accordingly address the lawfulness of EPA’s having error occurred because we did not EGUs should be regulated in the same ‘‘listed’’ EGUs under CAA section specifically discuss in this proposed manner as other categories for which the 112(c), leaving that matter to be decided rule whether we could or should statute requires regulation.’’ Id. if and when EPA adopted standards for regulate EGUs under CAA section (emphasis added). We were not EGUs under CAA section 112. Nowhere 112(n)(1) instead of CAA section foreclosing the possibility of any in the decision did the D.C. Circuit 112(d).63 The Agency validly listed alternative interpretation and our use of indicate that EPA must regulate EGUs EGUs in 2000 and listed sources must the term ‘‘must’’ should not detract from under CAA section 112(d). be regulated pursuant to CAA section the point we were trying to make. According to the commenter, the EPA 112(d). Specifically, we believe that Congress must consider both whether the Even if we agreed that regulation would have directed us to regulate regulation of EGUs is ‘‘appropriate and under CAA section 112(n)(1) was a EGUs under CAA section 112(n)(1)(A) if necessary’’ under section 112(n)(1) and viable option for EGUs, we would still that was its intent and, absent that address anew whether the Agency is have listed and regulated EGUs like mandate, the better reading of the authorized by section 112 to list EGUs other sources because CAA section statute is the one provided in the under section 112(c) at all. The 112(d) provides a statutory framework preamble to the proposed rule, which is commenter asserts that on the face of for regulating HAP emissions from that EGUs should be listed pursuant to the proposal, the EPA has not revisited sources and CAA section 112(n)(1) does CAA section 112(c) and subject to CAA the question whether the ‘‘listing’’ of not. We believe that even if CAA section section 112(d) emission standards. EGUs under section 112(c) is consistent The commenter also stated that the with congressional intent. 63 We note that in our January 2004 proposed EPA relied on CAA section 112(c)(6) to Response: The commenter’s rule, we solicited comment on whether section arguments are circular and it is difficult 112(n)(1)(A) provided independent authority to support a conclusion that EGUs must be regulate EGUs. We received several comments on regulated under CAA section 112(d). to fully determine exactly what its issue this issue, and we rejected the concept after The commenter takes the EPA’s is with EPA’s listing; however, it reviewing the comments and further considering statements out of context. The statement appears that the commenter believes the language of section 112(n)(1)(A) and the that EPA incorrectly relied on the New structure of section 112. As such, we proposed and in whole read: are finalizing that once the Agency determines that Jersey decision to justify the listing of Furthermore, the D.C. Circuit Court has EGUs. The commenter also appears to it is appropriate and necessary to regulate EGUs already held that section 112(n)(1) ‘‘governs under section 112, those sources are listed pursuant how the Administrator decides whether to argue that the Agency has never to subsection 112(c), as we did in December 2000, explained why it has the authority to and the Agency must set standards for those sources list EGUs’’ and that once listed, EGUs are pursuant to section 112(d). See section 112(c) and subject to the requirements of CAA section list EGUs at all. We disagree. (d)(1) (requiring establishment of 112(d) standards 112. New Jersey, 517 F.3d at 583. Indeed, the As stated in the preamble to the for listed source categories). D.C. Circuit Court expressly noted that proposed rule, CAA section 112(n)(1)(A)

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requires EPA to conduct a study of HAP interpretations on which it purports to of those emissions under CAA section emissions from EGUs and regulate EGUs base its rule.’’ 112. under CAA section 112 if we determine Response: We do not agree that we The commenter also argues that that regulation is appropriate and have improperly interpreted the statute Congress intended that EGUs be treated necessary, after considering the results as limiting our discretion in the manner differently from all other ‘‘major of the study. 76 FR 24981, 24986, and suggested by the commenter. The sources’’ to which the ‘‘delisting’’ 24998. The only condition precedent to commenter makes only one specific provisions of CAA section 112(c)(9), and regulating EGUs under CAA section 112 allegation in this comment and that the standard-setting provisions of CAA is a finding that such regulation is concerns the Agency’s conclusion that it section 112(d) necessarily and appropriate and necessary (after must establish CAA section 112(d) automatically apply. Therefore, conducting and considering the Utility standards for EGUs in light of the New according to the commenter, the EPA’s Study), and once that finding is made Jersey decision. The commenter does proposal to utilize the criteria of CAA the Agency has the authority to list not explain why that conclusion is section 112(c)(9) to inform its findings EGUs under CAA section 112(c) as the incorrect. As we state above and in the under CAA section 112(n)(1)(A) treats first step in the process of establishing preamble to the proposed rule, because EGUs exactly the same as all other major regulations under section 112. The D.C. EGUs are a CAA section 112(c) listed source categories, is contrary to Circuit agrees with that interpretation of source category, the Agency must congressional intent, and thus unlawful. the statute as evidenced by its statement establish CAA section 112(d) standards The commenter goes on to state that in in New Jersey that ‘‘section 112(n)(1)(A) or delist EGUs pursuant to CAA section exercising its discretion to define governs how the Administrator decides 112(c)(9). See New Jersey, 517 F.3d at ‘‘hazards to public health’’ as the phrase whether to list EGUs for regulation 582–83 (holding that EGUs remain is used in CAA section 112(n)(1)(A), the under section 112,’’ 517 F.3d at 582, and listed under section 112(c)); see also EPA would be better served to consider the Court’s statement directly CAA section 112(c)(2) (requiring the the ‘‘residual health risk’’ provisions of contradicts the commenter’s position. Agency to ‘‘establish emission standards CAA section 112(f)(2). Those provisions The EPA did not rely on the New under subsection [112] (d)’’ for listed provide a better analogy to the Jersey decision to justify the appropriate source categories and subcategories); 76 establishment of standards for EGUs and necessary finding as the commenter FR 24998–99. We concluded in the under CAA section 112 than do the ‘‘de- suggests. We based the finding in 2000 preamble to the proposed rule that we listing’’ criteria of CAA section 112(c)(9). on the extensive information available could not delist EGUs because our to the Agency at the time, and we The commenter believes the category- appropriate and necessary analysis confirmed the finding in the preamble specific criteria of paragraph (c)(9) are a showed that EGUs did not satisfy the to the proposed rule based on new poor fit for an evaluation of ‘‘hazards to CAA section 112(c)(9)(B)(i) delisting information. The commenter had ample public health’’ that should reasonably criteria. Id. We did not address in the opportunity to comment on the include such factors as the affected preamble to the proposed rule whether appropriate and necessary finding, and population, the characteristics of EGUs satisfied the CAA section it may challenge the basis of the listing exposure, the nature of the health 112(c)(9)(B)(ii) criteria because EGUs (i.e. the appropriate and necessary effects, and the uncertainties associated failed the first prong of the delisting finding) when EPA issues the final with the data. The commenter states provisions. Id. We reach the same standards. that, while CAA section 112(n)(1)(A) Comment: One commenter believes conclusion in the final rule and also does not expressly include any that the D.C. Circuit will condemn the address the delisting petition submitted requirement that EGU emissions be final rule as a result of EPA’s by this commenter. Because we cannot regulated with an ‘‘ample margin of ‘‘misapprehension’’ that upon making delist EGUs, we must regulate them safety,’’ that standard is more an ‘‘appropriate and necessary’’ finding, under CAA section 112(d). The appropriate than the ‘‘one-in-a-million’’ the Agency is compelled by the CAA to commenter has provided no legitimate cancer risk standard of CAA section adopt a regulatory standard for EGUs argument to rebut this conclusion. See 112(c)(9)(B)(i) that EPA proposes to under CAA section 112(d). According to also previous responses regarding employ. the commenter, a regulation will be regulation under section 112(n)(1)(A). Response: The commenter invalid if the regulation ‘‘ ‘was not based Comment: One commenter alleges acknowledges that EPA has broad on the [agency’s] own judgment’ ’’ but that EPA impermissibly relied on CAA discretion to interpret the phrase ‘‘ ‘rather on the unjustified assumption section 112(c)(9) to interpret ‘‘hazards to ‘‘hazard to public health’’ but argues that it was Congress’ judgment that such public health’’, and argues that the that the one thing we cannot do is use [a regulation] is desirable’ or required.’’ ‘‘residual risk’’ provisions in CAA the CAA section 112(c)(9)(B) delisting See Transitional Hospitals Corp. v. section 112(f)(2) are more appropriate provisions as a benchmark in making Shalala, 222 F.3d 1019, 1029 (D.C. Cir. for the establishment of standards for that interpretation. The commenter 2000), quoting Prill v. NLRB, 755 F.2d EGUs. The commenter stated that by asserts that the use of the delisting 941, 948 (D.C. Cir. 1985). The using CAA section 112(c)(9)(B)(i) in standard is clearly contrary to commenter further notes that the D.C. defining ‘‘hazards to public health’’, the Congressional intent but it does not Circuit has held that, where an agency Agency has seized on the one provide any substantive rebuttal to our wrongly construes a judicial decision as interpretation of the phrase that is conclusion that the CAA section compelling a particular statutory surely contrary to congressional intent 112(c)(9) standards reflects the level of interpretation, and thereby unduly and, thus, falls outside the permissible hazard which Congress concluded limits the scope of its own discretion, range of its interpretative discretion. warranted continued regulation. the agency’s action cannot be sustained. The commenter maintains that the Instead, the commenter reverted to its See, e.g., Phillips Petroleum Co. v. ‘‘delisting’’ criteria of CAA section argument that the statute treated EGUs FERC, 792 F.2d 1165, 1171 (D.C. Cir. 112(c)(9) are simply irrelevant to the differently. The EPA views the disparate 1986). The commenter believes the rule decision whether EGU HAP emissions treatment of EGUs in a different light is bound to be rejected and that the EPA will present any ‘‘hazards to public than commenter. While it is true that should ‘‘reconsider the legal health’’ sufficient to warrant regulation Congress established a different

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statutory provision governing whether does not require a conclusive link its 2005 reversal, and, thus, deserves no to add EGUs as a regulated source between HAP emissions and harm. One judicial deference. One commenter category under section 112, we do not commenter stated that the CAA grants stated that in 2005 EPA recognized the interpret CAA section 112(n)(1)(A) as the Administrator discretion in her potential for excessive regulation providing Congressional license to finding, and that discretionary decision created by CAA section 112 and ignore risks that Congress determined should not be overly scrutinized, citing determined that the 2000 finding lacked warranted regulation for all other source court opinion.67 In support of the foundation. categories. Because CAA section finding, one commenter stated that it Several commenters generally 112(c)(9) defines that level of risk, it is would not make sense for Congress to disagreed with the 2000 finding, with reasonable to consider it when limit HAP emissions from small two commenters stating that EPA did evaluating whether EGU HAP emissions businesses such as dry cleaners but to not have a rational justification for it pose hazards to public health. exempt U.S. EGUs, which are the largest and another claiming that it was fraught The commenter also suggests that the sources of many HAP emissions. One with misinformation and overestimating ‘‘ample margin of safety standard’’ of commenter agreed that finding was assumptions. One commenter claimed CAA section 112(f)(2) is a better fit than further supported because numerous that EPA did not explain the terms the one-in-a-million standard set forth control options were available to reduce ‘‘appropriate’’ and ‘‘necessary’’ in the in CAA section 112(c)(9)(B)(1) for HAP emissions. One commenter agreed 2000 finding and that the emission evaluating hazards to public health. The with the 2000 finding that the Agency control analysis was inadequate. Two commenter asserts that an evaluation of lacked sufficient evidence to conclude commenters stated that the 2000 finding ‘‘hazards to public health’’ should that non-Hg HAP from EGUs posed no was based on data that was more than include such factors as the affected hazard. 10 years old, which causes serious population, the characteristics of The commenters who generally concern regarding the validity of the exposure, the nature of the health supported the 2000 finding also findings because technology, the effects, and the uncertainties associated commented on specific aspects of the regulatory environment, and the with the data. However, the EPA did not finding. Several commenters asserted economic climate have evolved. rely solely on the delisting provisions that while the evidence on Hg alone Furthermore, because the Utility Report for evaluating hazards to public health supports the finding, the potential harm underestimated emissions controls that as commenter suggests. In fact, the EPA from non-Hg HAP further supported the EGUs would install by 2010 and considered all of the factors the 2000 finding. Several commenters noted additional controls that would be later commenter suggests in making our that new science continues to support required by the CSAPR, the basis for finding.64 Thus, we decline to adjust our the 2000 finding. Several commenters EPA’s 2000 finding has changed. approach to evaluating hazards to also stated that the ‘‘appropriate’’ Several commenters stated that a public health and the environment finding was further supported because ‘‘plausible link’’ between anthropogenic based on the comments. numerous control options were Hg and MeHg in fish is not an adequate reason for the 2000 finding. Several h. 2000 Finding (and 2005 Delisting) available at the time of the finding that would reduce HAP emissions. One commenters claim that EPA only Comment: Several commenters commenter concurred with EPA that identified health concerns for Hg (and generally support EPA’s 2000 finding regulating natural gas-fired EGUs was potentially Ni) but not other HAP from that regulating HAP emissions from not appropriate and necessary because coal-fired EGUs in the 2000 finding, EGUs under CAA section 112 is the impacts due to HAP emissions from and, thus, cannot regulate HAP other ‘‘appropriate and necessary.’’ According such units are negligible based on the than Hg because the 2000 finding to the commenters, the 2000 finding was results of the Utility Study. authorizes only the regulation of Hg. proper under the CAA and within EPA’s Several commenters addressed the One commenter questioned the Hg discretion, well-supported based on 2005 reversal of the 2000 finding. emissions underlying the 2000 finding, sound science available to the Agency at Several commenters specifically specifically the fraction of total the time on the harm from HAP emitted supported the vacatur of the 2005 deposition attributable to U.S. EGUS by EGUs, and no additional information action. Other commenters asserted that and the fact that EPA projected an makes the finding invalid. Several the 2005 action was proper, and that increase in U.S. EGU emissions from commenters cited the conclusions of the EPA reverted back to the 2000 finding 1990 to 2010 though emissions actually 65 66 Utility Study and Mercury Study, in the proposed rule without adequate declined. which they assert supported the finding explanation or support. Several Several commenters raised procedural and satisfied the only prerequisite for commenters cited the 2005 action as issues related to the 2000 finding. the finding. One commenter specifically invalidating the 2000 finding, Several commenters stated that the 2000 asserted that the 2000 finding was well- specifically noting that EPA concluded finding failed to provide public notice supported by the Utility Study’s that ‘‘no hazards to public health’’ and comment. According to the conclusions that (1) there was a link remained after accounting for emission commenters, the CAA requires that any between anthropogenic Hg emissions reductions under CAIR. These decision made under CAA section and MeHg found in freshwater fish, (2) commenters assert that EPA’s current 112(n) must go through public notice Hg emissions from coal-fired utilities position is illegal because EPA took the and comment. The commenters further were expected to worsen by 2010, and exact opposite position on the stated that the failure to provide public (3) MeHg in fish presents a threat to interpretation of the term ‘‘necessary’’ in notice and comment means that this public health from fish consumption. MACT is outside EPA’s statutory One commenter noted that the CAA 67 ‘‘Where a statute is precautionary in nature, the authority. One commenter stated that evidence difficult to come by, uncertain, or because the 2000 finding was never 64 76 FR 24992. conflicting because it is on the frontiers of scientific ‘‘fully ventilated’’ in front of the D.C. 65 U.S. EPA 1998. Study of Hazardous Air knowledge, the regulations designed to protect the Circuit, the EPA’s authority to regulate Pollutant Emissions from Electric Utility Steam public health, and the decision that of an expert Generating Units—Final Report to Congress. EPA– administrator, [courts] will not demand rigorous EGUs under CAA section 112(d) is 453/R–98–004a. February. step-by-step proof of cause and effect.’’ Ethyl Corp. directly at issue. The commenters claim 66 U.S. EPA, 1997. v. EPA, 541 F.2d 1, 28 (Ct. App. D.C. Circ. 1978). that specific issues did not undergo

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public notice and comment, including promulgated regulations requiring the regulate HAP emissions from EGUs due least-cost regulatory options, the impact use of available control technology and to the cancer risks identified in the of regulation on electricity reliability, other practices to reduce HAP emissions Utility Study or the potential concerns and EPA’s interpretation of the for more than 170 source categories. associated with other HAP emissions requirements under CAA section U.S. EGUs are the most significant from EGUs. Nothing in CAA section 112(n)(1)(A). One commenter claims source of HAP in the country that 112(n)(1)(A) suggests that EPA must that EPA attempted to provide after-the- remains unaddressed by Congress’s air determine that every HAP emitted by fact support for its 2000 finding with toxics program. The EPA listed EGUs in EGUs poses a hazard to public health or new legal analysis and new factual 2000 because the considerable amount the environment before EPA can find it information, contrary to New Jersey v. of available data supported the appropriate to regulate EGUs under EPA that held that EPA may not revisit conclusion that regulation of EGUs CAA section 112. In fact, the EPA its 2000 finding except through delisting under CAA section 112 was appropriate maintains that it must find it under CAA section 112(c)(9). One and necessary. That finding was valid at appropriate and necessary to regulate commenter stated that EPA’s 2000 the time, and EPA reasonably added EGUs under CAA section 112 if it finding should be reviewed when EPA EGUs to the CAA section 112(c) list of determines that any one HAP emitted issues the actual NESHAP.68 One sources that must be regulated under from EGUs poses a hazard to public commenter stated that the 2000 finding CAA section 112. health or the environment that will not ignored EO 12866. The EPA acknowledges that we did be addressed through imposition of the Response: EPA agrees with the not expressly define the terms requirements of the Act. The EPA commenters that the 2000 finding was appropriate and necessary in the 2000 disputes the commenters’ conclusion reasonable and disagrees with the finding, but the finding is instructive in that the 2000 finding was limited to Hg commenters asserting that the 2000 that it shows that EPA considered and Ni emissions, but, even if it were, finding was unreasonable or failed to whether HAP emissions from EGUs the EPA reasonably concluded that follow proper procedural requirements. posed a hazard to public health and the EGUs should be listed pursuant to CAA The EPA agrees that reviewing courts environment and whether there were section 112(c) based on the Hg and Ni defer to the reasoned scientific and control strategies available to reduce finding. As stated in the 2000 finding, technical decisions of an Agency HAP emissions from EGUs when cancer risks from some non-Hg metal charged with implementing complex determining whether it was appropriate HAP (including As, Cr, Ni, and Cd) were statutory provisions such as those at to regulated EGUs.71 When concluding not low enough to be to eliminate as issue in this case. As EPA stated in the it was necessary, the Agency stated that potential concern.75 Source categories preamble to the proposed rule, the EPA imposition of the requirements of the listed for regulation under CAA section maintains that the 2000 finding was Act would not address the identified 112(c) must be regulated under CAA reasonable and based on well-supported hazards to public health or environment section 112(d), and the D.C. Circuit has evidence available at the time, including from HAP emissions and that section stated that EPA has a ‘‘clear statutory the Utility Study, the Mercury Study,69 112 was the proper authority to address obligation to set emission standards for and the NAS study,70 which all showed HAP emissions.72 The EPA explained in each listed HAP’’. See Sierra Club v. the hazards to public health and the the preamble to the proposed rule its EPA, 479 F.3d 875, 883 (D.C. Cir. 2007), environment from HAP emitted from conclusion that the 2000 finding was quoting National Lime Association v. EGUs. New technical analyses fully supported by the information EPA, 233 F.3d 625, 634 (D.C. Cir. 2000). conducted by EPA confirm that it available at the time,73 and EPA stands Therefore, even if EPA concluded that remains appropriate and necessary to by the conclusions in that notice. CAA section 112(n)(1) authorized a regulate HAP emissions from EGUs. Furthermore, the EPA provided an different approach for regulating HAP Furthermore, the EPA agrees with the interpretation of the terms appropriate emissions from EGUs, the chosen course commenters on several points raised, and necessary that is wholly consistent which is supported by the CAA (i.e., specifically that EGUs were and remain with the 2000 finding. The EPA does listing under CAA section 112(c)) the largest anthropogenic source of not agree with the commenters that a requires the Agency to regulate under several HAP in the U.S., that risk quantification of emissions reductions CAA section 112(d) consistent with the assessments supporting the 2000 finding or a specific identification of the statute and case law interpreting that indicated potential concern for several available controls was necessary to provision. non-Hg HAP, and that several available support the 2000 finding and listing. The EPA disagrees that there is any control options would effectively reduce The EPA considered the Utility Study concern regarding the validity of the HAP emissions from U.S. EGUs. when making the finding, and that 2000 finding or that the emissions The EPA agrees with the commenters study clearly articulated the various information provided in the 2000 that Congress did not exempt EGUs alternative control strategies that EGUs finding makes the finding from section 112(d) HAP emission could employ to control HAP ‘‘questionable’’ as stated by some of the commenters. The EPA maintains that limits while simultaneously limiting emissions.74 As to emission reductions, the 2000 finding was sound and fully emissions at other sources with less the EPA cannot estimate the level of supported by the record available at the HAP emissions. Congress simply HAP emission reductions until the time, including the future year provided EPA with a separate path for Agency proposes a CAA section 112(d) emissions projections. Therefore, the listing EGUs by requiring that the standard after a source category is listed. Agency evaluate HAP emissions from The EPA disagrees with commenters listing of EGUs is valid based on that EGUs and determine whether regulation that suggest it was not ‘‘rational’’ to finding alone. Even though Hg under CAA section 112 was appropriate determine that it was appropriate to emissions have decreased since the and necessary. Since 1990, the EPA has 2000 finding instead of increasing as projected, the new technical analyses 71 65 FR 79830. 68 See UARG v. EPA, 2001 WL 936363, No. 01– 72 Id. confirm that Hg emissions from EGUs 1074 (D.C. Cir. July 26, 2001). 73 65 FR 24994–24996. continue to pose hazards to public 69 U.S. EPA, 1997. 74 See Chapter 13 of the Utility Study (U.S. EPA, 70 NAS, 2000. 1998). 75 76 FR 79827.

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health and the environment. The EPA The EPA disagrees with the 112(c)(9). See New Jersey, 517 F.3d at also indicated potential concern for commenters who raise concerns about 582–83. The EPA also disagrees with the several non-Hg HAP in the 2000 finding. the validity of the 2000 finding because commenter’s assertion that EPA It is well established that even small the data on which that finding was disregarded EO 12866 when making the amounts of HAP can cause significant based were more than 10 years old. The 2000 finding. As stated in the Federal harm to human health and the EPA made the finding at that time based Register notice, the 2000 finding did not environment. on the scientific and technical impose regulatory requirements or costs The EPA agrees with the commenters information available, and the finding is and was reviewed by the Office of who assert that the 2005 action was in wholly supported by that information. Management and Budget (OMB) in error and disagrees with the In addition, even though not required to accordance with the EO.76 do so, the EPA has since conducted new commenters that the 2005 action 2. New Technical Analyses invalidated the 2000 finding. As fully technical analyses utilizing the best described in the preamble to the information available in 2010 as several a. General Comments on New Technical proposal, the EPA erred in the 2005 years have passed since the 2000 Analyses action by concluding that the 2000 finding. These new analyses confirm Comment: Several commenters stated that HAP emissions from EGUs continue finding lacked foundation. The 2005 that the new analyses, including the risk to pose a hazard to public health and action improperly conflated the assessments and technology the environment, even after taking into ‘‘appropriate’’ and ‘‘necessary’’ analyses assessments, confirm that it remains account emission reductions that have by addressing the ‘‘after imposition of appropriate and necessary to regulate occurred since 2000 from promulgated the requirements of the Act’’ in the U.S. EGU HAP under CAA section 112. rules, settlements, and consent decrees. appropriate finding as well as the These commenters stated that the new necessary finding. The EPA also See 76 FR 24991. Contrary to the commenter’s analyses provide even more support indicated that it was not reasonable to assertion, the EPA did not violate CAA than the risk and technology interpret the necessary prong of the section 307(d) by not providing a notice information available at the time the finding as a requirement to scour the and comment opportunity before 2000 finding was made, including CAA for alternative authorities to making the December 2000 appropriate information on further developed regulate HAP emissions from stationary and necessary finding. One commenter emissions control technology, proven sources, including EGUs, when challenged EPA’s 2000 finding and and cost-effective control of acid gases Congress provided section 112 for that listing on the same grounds, and the using trona and dry sorbent injection, purpose. The EPA asserts that the 2000 D.C. Circuit dismissed the case because stabilized natural gas prices that makes finding was sound and fully supported CAA section 112(e)(4) clearly states that fuel switching and switching dispatch by the record available at the time for all listing decisions cannot be challenged to underutilized combined cycle plants the reasons stated in this final rule and until the Agency issues final emission more feasible, more information on the proposed rule. The 2005 action standards for the listed source category. ecosystem impacts from HAP, interpreted the statute in a manner See UARG v. EPA, 2001 WL 936363, No. ‘‘hotspots’’ from the deposition of Hg inconsistent with the 2000 finding and 01–1074 (D.C. Cir. July 26, 2001). The around EGUs, the potential for re- attempted to delist EGUs without EPA has provided the public an emission of Hg, updated emissions data complying with the mandates of CAA opportunity to comment on both the and future projections of HAP section 112(c)(9)(B). See New Jersey, 517 2000 finding and the 2011 analyses that emissions, and modern air pollution F.3d at 583 (vacating the 2005 support the appropriate and necessary modeling tools. One commenter states ‘‘delisting’’ action). In the preamble to determination as part of the proposed affordable control technology has been the proposed rule, the EPA set forth a rule, and anyone may challenge the in use in this sector for 10 to 40 years, revised interpretation of CAA section listing in the D.C. Circuit in conjunction and studies on EGU-attributable Hg 112(n)(1) that is consistent with the with a challenge to this final rule. The hazard has undergone two in-depth EPA statute and the 2000 finding. The EPA commenters could have also reviews, as well as a review by the NAS. also explained in the preamble to the commented on the CAA section Several commenters claimed that proposed rule why the 2005 action was 112(n)(1) (e.g., the Utility Study and the regulating U.S. EGUs is appropriate and not technically or scientifically sound. Mercury Study) studies in 2000 as they necessary to protect public health based The EPA specifically addressed the were included in the docket, but EPA is on information provided in the new errors associated with the 2005 action in not aware of any comments on those technical analyses. These commenters the preamble to the proposed rule, and studies. In any case, these studies were acknowledged the substantial commenters’ assertions do not cause us peer reviewed and considered the best reductions in HAP from recent to revisit these issues. The commenter is information available at that time. The regulations and new studies that also incorrect in suggesting that a EPA has fully complied with the confirm serious health risks from HAP change in interpretation is per se invalid rulemaking requirements of CAA exposure. One commenter stated that and provided no support for that section 307(d). new studies show higher risks to fetuses position. See National Cable & The EPA also disagrees with the than previously estimated, increasing Telecommunications Ass’n, et al., v. commenters’ characterization of the the potential for neurodevelopmental Brand X Internet Services, et al., 545 New Jersey case. The D.C. Circuit did effects in newborns. One commenter U.S. 967, 981 (discussing the deference not say, as one commenter suggested, noted that EGUs are a major source of provided to an Agency changing that EPA is not able to consider HAP, including HCl, HF, As, antimony, interpretations, the Court stated ‘‘change additional information that is collected Cr, Ni, and selenium, all of which is not invalidating, since the whole after the 2000 finding; instead, the Court adversely affect human health. The point of Chevron deference is to leave stated that EPA could not revise its commenter stated that because of these the discretion provided by ambiguities appropriate and necessary finding and health effects, the EPA has ample of a statute with the implementing remove EGUs from the CAA section evidence to support a determination Agency.’’) (Internal citations and 112(c) list without complying with the quotations omitted). delisting provisions of CAA section 76 65 FR 79831.

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that non-Hg HAP emissions present a analyses to confirm the 2000 finding. for a public health hazard from mercury risk to human health. The EPA disagrees with the emitted from U.S. EGUs.’’ 78 The SAB Other commenters disagreed that the commenter’s assertion that the Agency received the comments from Dr. Willie new analyses confirm that it remains is not authorized to consider new Soon, and had those comments appropriate and necessary to regulate information and at the same time unable available for consideration in their U.S. EGUs. One commenter claims that to use the information available in 2000 deliberations regarding the Hg risk EPA tried to use the new technical because, according to the commenter, analysis. The SAB specifically analyses to provide retroactive that information is ‘‘stale.’’ Under this supported elements of the analysis justification for the 2000 finding, which theory, the Agency could not ever make criticized by Dr. Willie Soon regarding only found ‘‘plausible links’’ of health an appropriate and necessary finding the use of the EPA RfD as a benchmark effects and ‘‘potential concerns’’ of prospectively, thereby excusing the for risk and the connection between Hg health effects of certain metal emissions, Agency from its obligations to protect emissions from U.S. EGUs and MeHg dioxins and acid based aerosols. The public health and the environment concentrations in fish. In addition, the commenter also asserted that none of because it did not diligently act in risk assessment methodology for the these new analyses demonstrate that undertaking its statutory responsibility non-Hg case studies is consistent with EGU regulation under section 112 is to establish CAA section 112(d) the methodology that EPA uses for necessary and appropriate. standards within two years of listing assessments performed for Risk and One commenter agreed that EPA may EGUs. See CAA section 112(c)(5). This Technology Review rulemakings, which supplement its finding with new is an illogical result that finds no basis underwent peer review by the SAB in information, analyses and arguments to in the statute. The EPA also disagrees 2009. 79 During the public comment reaffirm the 2000 finding up until EPA with the commenter’s assertion that period, the EPA also completed a letter issues final emissions standards. The EPA may not consider new analyses peer review of the methods used to commenter noted that the CAA does not conducted after the Utility Study in develop inhalation cancer risk estimates freeze the finding. However, another determining whether it is appropriate for Cr and Ni compounds, and those commenter argued that EPA does not and necessary to regulate EGUs under reviews were generally supportive. See have the authority to rely on new section 112 for the reasons set forth in above description of this peer review. technical analyses because the CAA the preamble to the proposed rule.77 For the final rulemaking, the EPA requires EPA to make the finding on the The EPA disagrees with the revised both risk assessments consistent basis of the Utility Study alone. commenter’s implication that EPA with recommendations from the peer According to that commenter, the EPA conducted the new analyses because of reviewers. The EPA relies on the SAB’s unreasonably stretched the language of alleged flaws in the 2000 finding. As review of the quality of the information CAA section 112 by considering new explained in detail in the preamble to supporting the analytical results. technical analyses. the proposed rule, the 2000 finding was Accordingly, contrary to the Citing a report from Dr. Willie Soon wholly valid and reasonable based on commenters’ assertions, the EPA acted that was submitted to the SAB, one the information available to the Agency consistently with the Information commenter stated that the new technical at that time, including the Utility Study. analyses supporting the proposed rule Quality Act as well as EPA’s and OMB’s Further, the EPA maintains that had it peer review requirements. do not conform to the Information complied with the statutory mandate to Quality Act, which requires that issue CAA section 112(d) standards b. Hg Emissions Estimates information relied on by EPA be within two years of listing EGUs, the 1. Hg Emissions From EGUs accurate, reliable, unbiased, and EPA would likely have declined to presented in a complete and unbiased conduct new analyses. The EPA Comment: The commenters addressed manner. conducted new analyses because over the 2005 and 2016 emissions estimates Response: The EPA agrees with the 10 years had passed since the 2000 for Hg and expressed concern that commenters that state that the new finding, and EPA wanted to evaluate inaccuracies in these emissions technical analyses (e.g., the risk HAP emissions from U.S. EGUs based estimates result in overestimates of risks assessments and technology assessment) on the most accurate information from Hg deposition. Further, confirm the 2000 finding and disagrees available, though the Agency was not commenters compared EPA’s 2010 with the commenters that state required to reevaluate the 2000 finding. estimate and 2016 estimate, and stated otherwise. The EPA also agrees with the In conducting the new analyses, the that it is not possible for 29 tons to be commenters that the 2000 finding was EPA used this updated information to a correct inventory total for Hg valid at the time it was made based on further support the finding. emissions in both years given expected the CAA section 112(n)(1) studies and The EPA strongly disagrees with the reductions from CSAPR. In addition, other information available to the commenter that stated that EPA failed to commenters specifically commented on Agency at that time. Furthermore, the conform to the Information Quality Act. assumptions included in the Integrated EPA agrees with commenters that the The EPA used peer reviewed Planning Modeling (IPM), including a final rule will lead to substantial information and quality-assured data in concern that Hg speciation factors used reductions in HAP emissions from all aspects of the technical analyses by IPM overestimate emissions in 2016. EGUs, that control of the HAP is used to support the appropriate and Other commenters noted that EGU estimated to lead to public health and necessary finding supporting this sources are the predominant source of environmental benefits as discussed in regulation. In addition, the EPA U.S. anthropogenic Hg emissions, the RIA, that Hg emissions from U.S. submitted the Hg Risk TSD to the SAB particularly the oxidized and particulate EGUs pose a hazard to public health, for peer review, which ‘‘supports the forms of Hg that are of primary concern and that non-Hg HAP emissions from overall design of and approach to the for Hg deposition. EGUs pose a hazard to public health. risk assessment and finds that it should Response: The EPA disagrees with Although these new analyses were not provide an objective, reasonable, and commenters’ assertions that the EPA’s required, the EPA agrees with the credible determination of the potential commenters that stated that EPA is 78 U.S. EPA–SAB, 2011. authorized to conduct additional 77 76 FR 24988. 79 U.S. EPA–SAB, 2010.

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emissions estimates overestimate risk. not impact the total amount of Hg inventories, global and regional While EPA agrees that the 2005 Hg emissions. photochemical modeling research, and emissions may be overestimated, such The EPA agrees with commenters observation-based assessments. A an overestimate in 2005 would actually who noted that EGU sources are the commenter stated that EPA has not lead to an underestimate of risk in 2016 predominant source of U.S. acknowledged the dramatic decline in and not an overestimate of risk, as anthropogenic Hg emissions, and in Hg emissions from U.S. EGUs since the claimed by the commenter, because the particular the oxidized and particulate late 1990s (approximately 50 percent) to ratio approach used by EPA to scale fish forms of Hg that are of primary concern the current level or consider the relative tissue data would underestimate risk if for Hg deposition. magnitude of Hg emissions from U.S. 2005 Hg estimates were overestimated. 2. Global Hg Emissions EGUs compared to other sources, Since the 2005 emissions are not used natural (such as fires) and human- as a starting point for 2016 emissions Comment: Several commenters stated caused. from IPM, any 2005 overestimate does that predicted Hg deposition relies Response: The EPA disagrees that not affect the 2016 emissions levels. The heavily on the amount of gaseous boundary and initial conditions used in 2016 emissions are computed by IPM elemental Hg used to define the modeling Hg deposition need based on forecasts of demand, fuel type, boundary and initial conditions of a adjustment for several reasons. First, the Hg content of the fuel, and the model, e.g., the Hg that enters the U.S. EPA does not use the first 10 days of the emissions reductions resulting from from outside the U.S. boundaries. The modeling simulation in the analysis, each unit’s configurations. See IPM commenters asserted that this is which is more than sufficient to remove Documentation for further information, especially important because Hg the influence of initial conditions on Hg which is available in the docket. No emissions from Asia—the region deposition estimates.86 Second, it is commenter has provided any evidence immediately upwind of North America difficult to accurately characterize the that the IPM 2016 emissions projection that affects U.S. Hg deposition speciation of Hg that flows into the U.S. methodology resulted in an significantly and also affects it the most from other countries due to the lack of overestimate. compared to other regions—are data near the boundaries of the expected to continue to The EPA acknowledges that the modeling domain. Third, the boundary increase.80 81 82 83 84 85 According to the current Hg emissions estimate would inflow for the CMAQ Hg modeling used commenter, this would affect the not be the same as the 2016 Hg in the Hg deposition modeling are based amount of Hg in the boundary and emissions estimate given that on a global model GEOS–CHEM initial conditions. The commenters simulation using a 2000 based global compliance with CSAPR is anticipated claim that EPA’s modeling did not inventory.87 A recently published to have some Hg co-benefits. For this account for these emission changes, comparison of global Hg emissions by reason, the EPA reflected emission thus leading to an overestimate of U.S. continent for 2000 and 2006 found that reductions anticipated from CSAPR in EGU-attributable deposition in 2016. total Hg emissions from Asia (and the Hg deposition modeling for 2016 in Several commenters noted that Hg Oceania) total 1,306 Mg/yr in 2000 and the Hg Risk TSD. In the final rule, the emissions from U.S. EGUs are small 1,317 Mg/yr in 2006.88 The EPA has EPA revised the estimate of Hg when compared to global Hg emissions determined that because the Asian Hg emissions remaining from U.S. EGUs in totals and natural sources within the emissions estimated in this study are 2016, which includes additional U.S. These commenters used a variety of nearly constant between 2005 and 2006, emission reductions anticipated from information to support alternative any adjustments to the boundary the final CSAPR. The revised estimate conclusions about the necessity to conditions or adjustments to modeled shows that U.S. EGUs would emit 27 control U.S. EGU emissions to reduce Hg deposition would be invalid and tons of Hg in 2016. Although EPA does Hg risk: global Hg emissions inappropriate. Recent research has not use the current Hg emissions shown that ambient Hg concentrations estimates in any of the risk calculations, 80 Jaffe D., Prestbo E., Swartzendruber P., Weiss- have been decreasing in the northern the EPA estimates that current Hg Penzias P., Kato S., Takami A., Hatakeyama S., Kajii hemisphere since 2000.89 Because emissions are 29 tons. Conclusions Y., 2005. ‘‘Export of Atmospheric Mercury From emissions from Asia have not Asia,’’ Atmospheric Environment, 39, 3029–3038. about the trend between current appreciably changed between 2000 and emissions and emissions in 2016 are 81 Jaffe D., Strode S., 2008. ‘‘Fate and Transport of Atmospheric Mercury From Asia,’’ 2006 and ambient Hg concentrations limited by the fact that different Environmental Chemistry, 5, 121. have been decreasing, ENVIRON’s methods were used to compute the two 82 Pacyna E.G., Pacyna J.M., Sundseth K., Munthe analysis contains incorrect assumptions estimates, as fully explained in the J., Kindbom K., Wilson S., Steenhuisen F., Maxson and we need not address them further. revised Emissions Overview memo in P., 2010. ‘‘Global Emission of Mercury to the Atmosphere From Anthropogenic Sources in 2005 For these reasons and the large the docket. and Projections to 2020,’’ Atmospheric uncertainties surrounding projected Hg The EPA disagrees with the Environment, 44, 2487–2499. commenter’s assertion that incorrect Hg 83 Pirrone N., Cinnirella S., Feng X., Finkelman 86 Pongprueksa, P., Lin, C.J., Lindberg, SE., Jang, emission factors result in incorrect 2016 R.B., Friedli H.R., Leaner J., Mason R., Mukherjee C., Braverman, T., Bullock, O.R., Ho, T.C., Chu, emissions. The 2016 projected Hg A.B., Stracher G.B., Streets D. G., Telmer K., 2010. H.W., 2008. ‘‘Scientific Uncertainties in ‘‘Global Mercury Emissions to the Atmosphere Atmospheric Mercury Models III: Boundary and emissions are not based on emissions From Anthropogenic and Natural Sources,’’ Initial Conditions, Model Grid Resolution, and Hg factors. The 2016 Hg emissions are Atmospheric Chemistry and Physics, 10, 5951– (II) Reduction Mechanism.’’ Atmospheric computed by the IPM based on forecasts 5964. Environment 42, 1828–1845. of demand, fuel type, Hg content of the 84 Streets, D.G., Zhang, Q., Wu, Y., 2009. 87 Selin, NE., Jacob, D.J., Park, R.J., Yantosca, ‘‘Projections of Global Mercury Emissions in 2050.’’ R.M., Strode, S., Jaegle, L., Jaffe, D. 2007. ‘‘Chemical fuel, and the emissions reductions Environmental Science & Technology 43, 2983– Cycling and Deposition of Atmospheric Mercury: resulting from each unit’s 2988. Global Constraints From Observations.’’ Journal of configurations. The speciation factors 85 Weiss-Penzias P., Jaffe D., Swartzendruber P., Geophysical Research-Atmospheres 112. referenced by the commenter provide a Dennison J.B., Chand D., Hafner W., Prestbo E., 88 Streets et al., 2009. basis for the speciation of total projected 2006. ‘‘Observations of Asian Air Pollution in the 89 Slemr, F., Brunke, E.G., Ebinghaus, R., Kuss, J., Free Troposphere at Mt. Bachelor Observatory in 2011. ‘‘Worldwide Trend of Atmospheric Mercury Hg emissions into particulate, divalent the Spring of 2004,’’ Journal of Geophysical Since 1995.’’ Atmospheric Chemistry and Physics gaseous, and elemental species, and do Research, 110, D10304. 11, 4779–4787.

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global inventories, the EPA concludes the peer reviewed scientific literature present results as estimates of lower and that the most appropriate technical shows that Hg emissions from U.S. upper bound limits. choice is to keep the Hg boundary EGUs in the U.S. significantly enhance Response: The EPA disagrees with the conditions the same between the 2005 Hg deposition and the response of information presented by ENVIRON. and 2016 simulations. ecosystems in the U.S. 90 91 92 93 The ENVIRON report is based on the The EPA also disagrees with the misapplication of multiple c. Hg Deposition Modeling commenters’ assertion that EPA has not incommensurate modeling studies and acknowledged the decline in Hg 1. General Comments on Deposition false premises which include the emissions for the U.S. EGUs since the Modeling incorrect notion that the boundary late 1990s. The EPA analyzed historical, Comment: Several commenters stated conditions are over-estimated and the current, and future projected Hg that according to the ENVIRON report, idea that EPA should use in-plume emissions from the power generation the EPA overestimated U.S. EGU- chemistry that has not been explicitly sector, as cited in the preamble to the attributable Hg deposition by 10 percent characterized and peer reviewed. proposed rule. The EPA also disagrees on average (and up to 41 percent in Reactions that may reduce gas phase with the commenters’ assertions that some areas). The commenters claim this oxidized Hg in plumes have not been EPA failed to consider the relative overestimation is the result of boundary explicitly identified in literature. Recent magnitude of Hg emissions from U.S. condition treatment, the exclusion of studies in central Wisconsin and central EGUs compared to other sources. As U.S. fire emissions,94 and Hg plume California suggest the opposite may noted in the Hg Risk TSD, the EPA chemistry approach. In addition, one happen; elemental Hg may be oxidized modeled Hg emissions from U.S. and commenter referenced the same to Hg(II) in plumes.97 98 Better field non-U.S. anthropogenic and natural ENVIRON report and stated that before study measurements and specific sources to estimate Hg deposition across implementation of controls required by reaction mechanisms need to be the country. The EPA also determined the proposed rule, areas with relatively identified before making conclusions the contribution of Hg emissions from high EGU-attributable Hg deposition about potential Hg in-plume chemistry U.S. EGUs to total Hg deposition in the (one-fifth or more of total deposition) in or applying surrogate reactions in U.S. by running modeling simulations 2016 constitute less than 0.25 percent of regulatory modeling. The possibility for 2005 and 2016 with Hg emissions the continental U.S. area, and only three that Hg(0) is oxidized to Hg(II) in from U.S. EGUs set to zero. Based on the grid cells have EGU contributions plumes suggests coal-fired power plant Hg Risk TSD, Hg emissions from U.S. exceeding half of total deposition. Hg contribution inside the U.S. may be EGUs pose a hazard to public health Another commenter suggested that underestimated in EPA modeling. based on the total of 29 percent of current research shows that models of The EPA asserts that the numbers modeled watersheds potentially at-risk. Hg atmospheric fate and transport suggested by the commenter are Our analyses show that of the 29 overestimate the local and regional inaccurate, as it is not appropriate to percent of watersheds with population impacts of some anthropogenic sources, adjust EPA’s deposition estimates based at-risk, in 10 percent of those such as U.S. EGUs. Thus, according to on previous Hg modeling done with watersheds U.S. EGU deposition alone the commenter, calculated contributions older Hg chemistry, in-plume reactions leads to potential exposures that exceed to Hg deposition and fish tissue MeHg that have not been explicitly identified, the MeHg RfD, and in 24 percent of levels from these sources represent and erroneous adjustments to Hg those watersheds, total potential upper bounds of actual boundary inflow. Recent research has exposures to MeHg exceed the RfD and contributions,95 96 and EPA should shown that ambient Hg concentrations U.S. EGUs contribute at least 5 percent have been decreasing in the northern to Hg deposition. 90 Caffrey et al., 2010. hemisphere since 2000.99 The EPA The commenters suggest that Hg 91 Driscoll, C. T., Han, Y.-J., Chen, C. Y., Evers, declines to revise this analysis as emissions from U.S. EGUs represent a D. C., Lambert, K. F., Holsen, T. M., et al., (2007). commenter suggests for several reasons, limited portion of the total Hg emitted ‘‘Mercury Contamination in Forest and Freshwater including available evidence indicates worldwide, including anthropogenic Ecosystems in the Northeastern United States.’’ that emissions from China have not and natural sources. While EPA BioScience, 57(1). 92 Keeler, G.J., Landis, M.S., Norris, G.A., appreciably changed between 2000 and acknowledges that Hg emissions from Christianson, E.M., Dvonch, J.T., 2006. ‘‘Sources of 2006 100 and ambient Hg concentrations U.S. EGUs are a small fraction of the Mercury Wet Deposition in Eastern Ohio, USA.’’ have decreased, the commenter total Hg emitted globally, it views the Environmental Science & Technology 40, 5874– inappropriately comingled out–of-date environmental significance of Hg 5881. emissions from U.S. EGUs and other 93 White, E.M., Keeler, G.J., Landis, M.S., 2009. Hg modeling simulations with EPA ‘‘Spatial Variability of Mercury Wet Deposition in domestic sources as a more germane results, and ENVIRON’s analysis has not Eastern Ohio: Summertime Meteorological Case undergone any scientific peer review consideration. Mercury is emitted from Study Analysis of Local Source Influences.’’ EGUs in three forms. Each form of Hg Environmental Science & Technology 43, 4946– and presents information with incorrect has specific physical and chemical 4953. assumptions as noted in this response. 94 Finley, B.D., Swartzendruber, P.C., Jaffe, D.A., The EPA also disagrees with the properties that determine how far it 2009. ‘‘Particulate Mercury Emissions in Regional travels in the atmosphere before commenter’s interpretation of the Wildfire Plumes Observed at the Mount Bachelor applicability of wildfire Hg emissions to depositing to the landscape. Although Observatory.’’ Atmospheric Environment 43, 6074– gaseous oxidized Hg and particle-bound 6083. Hg are generally local/regional Hg 95 Seigneur, C., Lohman, K., Vijayaraghavan, K., dispersion from local and regional emission Shia, R.L., 2003. ‘‘Contributions of global and sources, rural Central Wisconsin, USA.’’ deposition concerns, all forms of Hg regional sources to mercury deposition in New York Atmospheric Chemistry and Physics 10, 4467–4476. may deposit to local or regional State.’’ Environmental Pollution 123, 365–373. 98 Rothenberg, SE., McKee, L., Gilbreath, A., Yee, watersheds. U.S. coal-fired power plants 96 Seigneur, C., Vijayaraghavan, K., Lohman, K., D., Connor, M., Fu, X.W., 2010. ‘‘Wet deposition of account for over half of the U.S. Karamchandani, P., Scott, C., 2004. ‘‘Modeling the mercury within the vicinity of a cement plant before and during cement plant maintenance.’’ controllable emissions of the quickly atmospheric fate and transport of mercury over North America: power plant emission scenarios.’’ Atmospheric Environment 44, 1255–1262. depositing forms of Hg. Although Fuel Processing Technology 85, 441–450. 99 Slemr et al., 2011. emissions from international Hg sources 97 Kolker, A., Olson, M.L., Krabbenhoft, D.P., 100 Streets et al., 2009. contribute to Hg deposition in the U.S., Tate, M.T., Engle, M.A., 2010. ‘‘Patterns of mercury 101 Finley et al., 2009.

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this assessment. Finley et al., (2009) 101 2. Chemical Reactions phase Hg could be reduced and suggests caution when using their field Comment: Several commenters stated postulate a possible pathway. data to make assumptions about Hg(p) that the CMAQ modeling fails to Recent studies in central Wisconsin emissions from wildfires; the estimated account for the chemical reduction of and central California suggest the particulate Hg emissions from wildfires gaseous ionic Hg to elemental Hg that opposite may happen; elemental Hg is based on one field site with a limited may be oxidized to Hg(II) in may occur in EGU plumes. The 108 109 sample size, and the assumptions made commenters noted that EPA did not use plumes. Better field study (such as the observed Hg(p) to carbon the Electric Power Research Institute’s measurements and specific reaction monoxide ratios at this location) may (EPRI) Advanced Plume-in-Grid mechanisms need to be identified before 102 not be valid on a broader scale. Treatment, which includes a surrogate making conclusions about potential Hg Mercury emissions from wildfires are a reaction to reduce gaseous ionic Hg to in-plume chemistry or applying re-volatilization of previously deposited elemental Hg inside plumes. Multiple surrogate reactions in regulatory 103 Hg. Given that electrical generating commenters claimed that the reduction modeling. Currently, models such as power plants are currently and of reactive gaseous Hg to gaseous Advanced Plume Treatment (APT) use a historically have been among the largest elemental Hg has been reported in surrogate reaction for the potential Hg-emitting sources, the inclusion of reactive gas phase Hg reduction that power plant plumes and that supporting 110 wildfire emissions in a modeling data include atmospheric may or may not occur in plumes. assessment would necessarily increase concentrations of speciated Hg Reactions that may reduce gas phase the contribution from this emissions measured downwind of power plant oxidized Hg in plumes have not been sector. stacks at ground-level monitor sites and explicitly identified in literature. The The EPA disagrees with the assertion dispersion model predictions.106 107 A application of potentially erroneous in- that EPA failed to consider the relative detailed description of various plume plume chemistry that is a fundamental magnitude of Hg emissions from U.S. measurement studies is provided in component of APT would be EGUs compared to other sources and EPRI Comments, Section 3.4: Plant inappropriate. In addition, the APT is disagrees with the interpretation of EGU Bowen, Georgia, Plant Pleasant, not available in the most recent version deposition presented in the ENVIRON Wisconsin, and Plant Crist, Florida. One of CMAQ. It would be inappropriate for report. As noted in the Hg Risk TSD, the commenter believed the impact of grid EPA to apply an out of date EPA modeled Hg emissions from U.S. resolution (12 km sized grid cells) on photochemical model with in-plume and non-U.S. anthropogenic and natural the CMAQ modeling was not chemistry that has not been shown to sources to estimate Hg deposition across appropriately addressed by EPA. Their exist. the country. The EPA also determined The EPA agrees with the commenter concerns due to grid resolution include the contribution of Hg emissions from that the CMAQ modeling with 12 km the notion that a source’s emissions will U.S. EGUs to total Hg deposition in the grid resolution may provide a lower be averaged over the entire grid cell. U.S. by running modeling simulations bound estimate on EGU contribution as According to the commenter, such for 2005 and 2016 with Hg emissions higher impacts using finer grid averaging causes an artificially fast from U.S. EGUs set to zero. Hg resolution are possible. The dilution that smoothes out areas of high emissions from U.S. EGUs pose a hazard commenter’s assertion that EGU impacts and low deposition, which may limit to public health based on the total of 29 are likely higher further supports the the ability of the model to simulate percent of modeled watersheds final conclusions of the exposure smaller areas of localized high potentially at-risk. Our analyses show modeling assessment. The EPA notes deposition. This commenter believed that of the 29 percent of watersheds that the application of a photochemical that using the APT would address these with population at-risk, in 10 percent of model at a 12 km grid resolution for the those watersheds U.S. EGU deposition issues. Response: The EPA disagrees with the entire continental U.S. is more robust in alone leads to potential exposures that commenters’ claims that oxidized Hg terms of grid resolution and scale that exceed the MeHg RfD, and in 24 percent chemically reduces to elemental anything published in literature and of those watersheds, total potential mercury within the plume. There is no represents the most advanced modeling exposures to MeHg exceed the RfD and evidence of these chemical reactions in platform used for a national Hg U.S. EGUs contribute at least 5 percent the scientific literature. The references deposition assessment. to Hg deposition. The ENVIRON report cited by the commenters are from non- provides no risk analysis of EGU 3. Modeled Deposition Compared to peer reviewed reports and conference contribution. Measured Deposition The EPA disagrees that research 104 105 proceedings. The EPA does not consider Comment: Multiple commenters presented by the commenter shows that information presented at conferences or expressed dissatisfaction related to U.S. EGU impacts are over-estimated. industry reports to be peer reviewed EPA’s model performance evaluation of The commenter’s references do not literature, and consideration of oral CMAQ estimated Hg deposition. The support this statement. The references presentation material would be commenters stated that EPA failed to provided by the commenter are based inappropriate. Further, even these cited evaluate the CMAQ model against real- on Hg modeling that uses models that references do not provide sufficient world measurements and that EPA fails are no longer applied and that are based information for incorporating the to provide first-hand information on wet on out-dated Hg chemistry and supposed reactions into the modeling and dry deposition processes. The deposition assumptions. Given the (e.g., specific chemical reactions, commenters also stated that EPA needs advances in Hg modeling since the early reaction rates, etc.); rather, the cited 2000s, the EPA does not believe an references only suggest that oxidized gas 108 Kolker et al., 2010. upper and lower bound estimate is 109 Rothenberg et al., 2010. 103 necessary. Wiedinmyer, C., Friedli, H., 2007. ‘‘Mercury 110 Vijayaraghavan, K., Seigneur, C., emission estimates from fires: An initial inventory Karamchandani, P., Chen, S.Y., 2007. for the United States.’’ Environmental Science & ‘‘Development and application of a multipollutant 100 Streets et al., 2009. Technology 41, 8092–8098. model for atmospheric mercury deposition.’’ 101 Finley et al., 2009. 104 Seigneur et al., 2003. Journal of Applied Meteorology and Climatology 46, 102 Id. 105 Seigneur et al., 2004. 1341–1353.

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to assess how predicted values of Hg against routine monitor networks for point source mercury modeling use deposition compare to Mercury such as AMNet or SEARCH would be an approach to aggregate the operational Deposition Network (MDN) data and useful for this particular modeling performance metrics across many how predicted values of ambient application. The AMNet Hg network did monitor locations as did EPA; however, speciated Hg concentrations compare to not exist in 2005, which is EPA’s these articles calculate long term annual measurement networks like AMNet and baseline model simulation time period, averages of modeled and observed total SEARCH. In addition, commenters and the SEARCH network started Hg wet deposition before estimating stated that EPA used highly aggregated making preliminary measurements of performance metrics. It is common performance metrics comparing model Hg at one or two sites in 2005. In practice to pair modeled estimates and estimates to observations that they addition, measurement artifacts related observations in space and time (weekly believe result in a degraded and lenient to gaseous oxidized Hg are difficult to in this case) and estimate performance operational evaluation of the modeling quantify and make direct comparison to metrics, then average all the metrics system. A commenter suggested that model estimates problematic.112 together. The latter is the approach EPA’s model performance provides no Considering the problems associated taken by the EPA and should have been confidence for the intended purpose of with TEKRAN measurements of ambient taken by the studies presented by the estimating deposition near point Hg and the sparse nature of routine commenter. The EPA used a more sources. One commenter simply noted measurements in the U.S., the EPA did stringent approach to match that EPA’s model over-estimated total not compare ambient Hg against model observations and predictions and Hg wet deposition at MDN monitors. estimates. aggregation of operational model Finally, several commenters noted that The EPA disagrees that the model performance. The EPA agrees that the EPA presented a negative modeled wet performance presented in the air quality commenter accurately restated total wet deposition total in the Air Quality TSD is insufficient. The EPA asserts that deposition model performance Modeling TSD, which is physically the model performance evaluation is information provided by the EPA in the impossible. generally similar to the level of model Air Quality Modeling TSD. To provide Response: EPA agrees with the performance presented in literature. context, other Hg modeling studies commenters that the negative estimate One commenter presented the results of show a positive bias for annual total Hg for wet deposition in the Air Quality several Hg modeling studies as wet deposition.118 119 An annual Hg Modeling TSD was an error. This error providing information that the modeling application done by reflected an incorrect calculation in the commenter believes to be relevant for ENVIRON 120 and the Atmospheric and post-processing of model and this assessment in terms of model Environmental Research for Lake observation pairs that only influenced performance metric estimation and the Michigan Air Directors Consortium the calculation of model performance level of model performance evaluation show seasonal average normalized bias metrics. The error has been fixed, and shown for assessments modeling Hg between 70 and 158 percent and the model performance metrics in the near point sources. For example, one seasonal average normalized error revised Air Quality Modeling TSD have cited study titled ‘‘Modeling Mercury in between 72 and 503 percent.121 These been updated. This error did not affect Power Plant Plumes’’ models near- results indicate a very large over- Hg deposition. In response to source Hg chemistry from U.S. EGUs, estimation tendency. The model comments, the EPA provided additional but provides absolutely no information performance shown by EPA is model performance evaluation by about model performance evaluation.113 consistent with other long-term Hg season to the revised Air Quality Another commenter identified two modeling applications. studies as supposedly having Hg Modeling TSD. In addition, in response 4. Excess Local Deposition From Hg to comments, the EPA also included modeling results that are applicable to EPA’s analysis.114 115 These studies Emissions From U.S. EGUs (Deposition model performance evaluation for total Hotspots) Hg wet deposition for the 36 km present similar model performance modeling domain in the revised Air metrics as EPA. The EPA disagrees that Comment: One commenter stated that Quality Modeling TSD. the Agency used ‘‘highly aggregated reducing Hg will benefit local The EPA disagrees that it did not performance metrics’’ that result in environments. The commenter stated conduct an assessment comparing degraded and lenient model evaluation. that a 2007 study confirmed the CMAQ total Hg wet deposition The studies presented 116 117 as relevant presence of Hg ‘‘hotspots’’ downwind estimates to MDN data. The Air Quality from coal-fired power plants and Modeling TSD clearly shows a 112 Lyman, S.N., Jaffe, D.A., Gustin, M.S., 2010. confirmed that coal-fired power plants ‘‘Release of mercury halides from KCl denuders in within the U.S. are the primary source comparison of CMAQ estimated total Hg the presence of ozone.’’ Atmospheric Chemistry and wet deposition with MDN data for the Physics 10, 8197–8204. of Hg to the Great Lakes and the entire length of the modeling period. 113 Lohman et al., 2006. Chesapeake Bay.122 The commenter also The CMAQ wet deposition of Hg has 114 Seigneur, C., Lohman, K., Vijayaraghavan, K., stated that the study is consistent with Jansen, J., Levin, L., 2006. ‘‘Modeling atmospheric a major Hg deposition study conducted been and will continue to be extensively mercury deposition in the vicinity of power 111 evaluated against MDN sites. There is plants.’’ Journal of the Air & Waste Management 118 no dry deposition monitoring network, Association 56, 743–751. Id. which precludes evaluating CMAQ dry 115 Vijayaraghavan, K., Karamchandani, P., 119 Vijayaraghavan et al., 2007. 120 deposition processes. The EPA disagrees Seigneur, C., Balmori, R., Chen, S.–Y., 2008. Yarwood, G, Lau, S., Jia, Y., Karamchandani, ‘‘Plume-in-grid modeling of atmospheric mercury.’’ P., Vijayaraghavan, K. 2003. Final Report: Modeling that an evaluation of ambient speciated Journal of Geophysical Research-Atmospheres 113. Atmospheric Mercury Chemistry and Deposition 116 Seigneur, C., Lohman, K., Vijayaraghavan, K., with CAMx for a 2002 Annual Simulation. Prepared 111 Bullock, O.R., Atkinson, D., Braverman, T., Jansen, J., Levin, L., 2006. ‘‘Modeling atmospheric for Wisconsin Department of Natural Resources. Civerolo, K., Dastoor, A., Davignon, D., Ku, J.Y., mercury deposition in the vicinity of power http://www.gypsymoth.wi.gov/air/toxics/mercury/ _ _ Lohman, K., Myers, T.C., Park, R.J., Seigneur, C., plants.’’ Journal of the Air & Waste Management hg X97579601 appB.pdf. Selin, NE., Sistla, G., Vijayaraghavan, K., 2009. ‘‘An Association 56, 743–751. 121 Yarwood et al., 2003. analysis of simulated wet deposition of mercury 117 Vijayaraghavan, K., Karamchandani, P., 122 Evers, David C. et al., 2007. ‘‘Biological from the North American Mercury Model Seigneur, C., Balmori, R., Chen, S.-Y., 2008. Mercury Hotspots in the Northeastern United States Intercomparison Study.’’ Journal of Geophysical ‘‘Plume-in-grid modeling of atmospheric mercury.’’ and Southeastern Canada,’’ Bioscience. Vol. 57 No. Research-Atmospheres 114. Journal of Geophysical Research-Atmospheres 113. 1. p. 29.

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by the EPA and the University of hotspots in this proposed rule. Those deposition and concentrations did not Michigan that concluded that same commenters cited a previous EPA differ in a statistically significant approximately 70 percent of Hg wet definition of hotspots as ‘‘a waterbody manner among these three sites and that deposition resulted from local fossil fuel that is a source of consumable fish with the concentrations values were similar emissions in the region.123 MeHg tissue concentrations, attributable to those from Mercury Deposition One commenter agreed with the solely to utilities, greater than EPA’s Network (MDN) sites that are more than Agency’s assessment of the potential for MeHg water quality criterion of 0.3 mg/ 50 km away from Plant Crist located deposition ‘‘hotspots’’ that shows that kg’’ (milligrams per kilogram).126 The along the Northern Gulf of Mexico coast. Hg deposition near EGUs can be three same commenters stated that it is Another commenter stated that Plant times as large as the regional average. unclear why EPA changed from defining Crist installed a wet scrubber and has The commenter stated that this excess a hotspot by fish tissue MeHg operated that scrubber continuously Hg deposition would substantially concentration to defining a hotspot by since December 2009. The commenter increase the health and environmental depositional excess. Two commenters stated that the scrubber reduces total Hg risks associated with emissions at these suggested that a Hg hotspot is a specific emissions by about 70 percent and sites. The same commenter also stated location that is characterized by reduces emissions of reactive gaseous that EPA applied a conservative elevated concentrations of Hg exceeding Hg by about 85 percent. The commenter methodology to quantify near-source Hg a well-established criterion, such as a cited a non-peer reviewed conference deposition. The commenter stated that reference concentration (RfC) when presentation 131 that reported changes in maximum excess local Hg deposition compared to its surroundings. Those Hg wet deposition relative to historic may be significantly underestimated by same commenters stated that identifying measurements. The commenter stated averaging high deposition sites Hg hotspots should not be constrained that, taken collectively, these findings downwind of an EGU in the direction of to locations where concentrations can show that increased local total Hg prevailing winds with lower excess be attributed to a single source or deposition, possibly due to EGUs, and deposition at locations close to but sector.127 One of those two commenters deposition changes due to changes in frequently upwind of the facility. The noted that others have defined EGU emissions, are small. same commenter suggests that had EPA ‘‘hotspots as a spatially large region in Two commenters stated that a study 2 used CMAQ and individual 12x12 km which environmental concentrations far by the Department of Energy (DOE) that grid cells to quantify local deposition, exceed expected values, with such collected and analyzed soil and the model could increase the excess Hg values (i.e. concentrations) being 2 to vegetation samples for Hg near three deposition at these locations three standard deviations above the U.S. coal-fired power plants—one in 128 significantly and place them at even relevant mean.’’ North Dakota, one in Illinois, and one in greater risk of adverse health and One commenter stated that Hg Texas—found no strong evidence of environmental effects of HAP from U.S. concentrations are not always highest at ‘‘hotspots’’ around these three plants. EGUs. sites closest to a major source. The Two commenters stated that analysis One commenter stated that the 129 commenter referred to a study that of long-term trends in Hg emissions Hubbard Brook Research Foundation demonstrated that concentrations of from coal-fired EGUs and wet issued a report in 2007 that identified atmospheric reactive gaseous Hg, deposition in Florida concluded that five Hg hotspots, one of which was in gaseous elemental Hg, and fine statistical analysis does not show the Adirondack Park, along with four particulate Hg were lower when evidence of a significant relationship suspected hotspots.124 The commenter measured 25 km from a 1,114 MW coal- between temporal trends in Hg stated that this study also provides a fired EGU than when measured 100 km emissions from coal-fired EGUs in good description of the impacts of Hg on away. The commenter stated that these Florida and Hg concentrations in the Common Loon, which is a symbol findings contradict the idea, implicit in precipitation during 1998 to 2010. of a healthy Adirondack environment. EPA’s hotspot analysis, that reactive Two commenters stated that the Hg One commenter stated that there is gaseous Hg decreases with distance Risk TSD presents no information, there is no evidence of Hg hotspots due from a large point source. to local deposition associated with coal- One commenter provided information summary statistics, and/or actual fired power plants. According to the from a non-peer reviewed report with calculations showing how excess commenter, the EPA’s use of a 50 km wet Hg deposition measurements deposition within 50 km of an EGU radius to calculate hotspots is flawed. downwind from the coal-fired power source is obtained. The commenters The commenter stated that modeling plant Crist in Pensacola, FL. The stated that by assessing only Hg studies show that deposition of Hg commenter stated that using the same deposition attributable to EGUs, the emitted from power plants is not data from these same wet deposition EPA fails to provide a context for all confined to a 50-km radius around the sites, one study 130 found that Hg wet other sources of Hg deposition. The plants and that most emissions from commenters stated that the Agency does power plants travel beyond 50 km.125 126 U.S. EPA, 2005. 40 CFR Part 63 [OAR–2002– not explain why deposition from the top Several commenters stated that the 0056; FRL–7887–7] RIN 2060–AM96. Revision of 10 percent of EGU Hg emitters does not December 2000 Regulatory Finding on the decline, despite substantial reductions EPA does not adequately define Emissions of Hazardous Air Pollutants From Electric Utility Steam Generating Units and the in modeled Hg emissions from those 123 Cohen, et al., 2004. ‘‘Modeling the Removal of Coal- and Oil-Fired Electric Utility sources between 2005 and 2016. Atmospheric Transport and Deposition of Mercury Steam Generating Units From the Section 112(c). to the Great Lakes,’’ Environmental Research 95, Final rule, March 29. ‘‘Atmospheric deposition of mercury and major (247–265). 127 Evers et al., 2007. ions to the Pensacola (Florida) watershed: spatial, 124 Driscoll, C.T., D. Evers, K.F. Lambert, N. 128 Sullivan T., 2005. ‘‘The Impacts of Mercury seasonal, and inter-annual variability.’’ Kamman, T. Holsen, Y-J. Han, C. Chen, W. Goodale, Emissions from coal-fired Power Plants on Local Atmospheric Chemistry and Physics 10, 5425–5434. T. Butler, T. Clair, and R. Munson. Mercury Deposition and Human Health Risk.’’ Presented at 131 Krishnamurthy N., Landing W.M, Caffrey J.M., Matters: Linking Mercury Science with Public the Pennsylvania Mercury Rule Workgroup 2011. ‘‘Rainfall Deposition of Mercury and Other Policy inthe Northeastern United States. 2007. Meeting, October 28. Trace Elements to the Northern Gulf of Mexico.’’ Hubbard Brook Research Foundation. Science Links 129 Kolker, et al., 2010. Presented at the 10th International Conference on Publication. Vol. 1, no. 3. 130 Caffrey, J.M., Landing, W.M., Nolek, S.D., Mercury as a Global Pollutant, Halifax, Nova Scotia, 125 Seigneur et al., 2006. Gosnell, K.J., Bagui, S.S., Bagui, S.C., 2010. Canada, July 27.

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According to the commenters this average EGU-attributable deposition does not detract from the overall finding implies that the top 10 percent EGUs (based on CMAQ modeling of Hg that around some power plants with may have approximately as much of a deposition) in the area 500 km around high levels of Hg emissions excess local regional effect as a local effect. each plant and the average EGU- deposition is on average three times the Two commenters stated that the attributable deposition in the area 50 km regional EGU-attributable deposition CMAQ model has limitations when around each plant. The difference around those plants. used to predict local deposition and between those two values is the excess The EPA disagrees that the Hg Risk tends to overestimate local deposition. local deposition around the plant. The TSD did not provide sufficient The commenters stated that modeling EPA does not suggest Hg emissions from information regarding the excess local studies using either a plume model or power plants stop at 50 km from the deposition calculation. Nonetheless, the an Eulerian model predict that 91 to 96 source. Some portion of EGU emissions EPA has further clarified the percent of the Hg emitted by an EGU deposit before 50 km, and some portion methodology in the new Local travels beyond 50 km.132 travels beyond 50 km. In addition, Hg Deposition TSD, including further Response: The EPA agrees with the disperses as it transports, so the average descriptions of the method used to commenters that stated that Hg EGU contribution can be lower in areas calculate the local and regional emissions from EGUs deposit locally beyond 50km relative to areas within deposition around power plants along and regionally and contribute to excess 50km even though Hg emissions from with maps and tables of results. local deposition near U.S. EGUs. The EGUs are depositing into U.S. The EPA disagrees with the EPA acknowledges additional watersheds. commenters that stated that the 133 studies cited by those commenters The EPA disagrees with some discussion of local deposition in the Hg that corroborate EPA’s conclusions. commenters’ interpretation of the Risk TSD did not demonstrate that Hg However, the EPA disagrees with those analysis as being focused on local deposition from the top 10 percent of commenters’ characterization of the deposition from all sources. In fact, the EGU Hg emitters declines. Table 1 of the methodology used to calculate the focus was on excess local deposition, new Local Deposition TSD clearly potential for excess local deposition. In rather than all local deposition. The shows that mean local deposition response, the EPA has clarified the EPA has clarified the purpose of the (within 50km of a plant) for the top 10 methodology in the new TSD entitled excess local deposition analysis in the percent of emitters declines from 4.89 ‘‘Technical Support Document: new TSD. The EPA agrees that all EGUs micrograms per cubic meter (mg/m3) to Potential for Excess Local Deposition of add to local deposition, however, not all 1.18 mg/m3. What does not change is the U.S. EGU Attributable Mercury in Areas EGUs have local deposition that greatly percent local excess for EGU- near U.S. EGUs,’’ which is available in exceeds regional deposition, which is attributable Hg deposition. This implies the docket. the relevant question. The EPA that while Hg deposition from EGUs is The EPA agrees that there is no disagrees that the DOE study referenced declining, there is still an excess generally agreed-upon definition of by the commenters attempted to assess contribution to local deposition relative ‘‘hotspot.’’ As discussed in the preamble the same analytical question as EPA’s to regional deposition; e.g., because of and TSD, for the purposes of the analysis. The DOE study focused on dispersion, the contribution to average appropriate and necessary finding, the comparisons of total deposition near deposition outside 50 km from the plant EPA determined that information on the and far from power plants. The EPA’s is lower than the contribution to average potential for excess deposition of Hg in analysis did not focus on total Hg deposition within 50 km of the plant. areas surrounding power plants would deposition, because as EPA be useful in informing the finding. The The EPA disagrees that the acknowledges throughout its analysis, 134 EPA disagrees with some commenters global sources of Hg deposition account information provided by the who misinterpreted the intent of the Hg for a large percentage of total Hg commenter regarding the Crist plant and deposition hotspot analysis. deposition. In addition, including global other coal-fired power plants in Florida Specifically, the analysis is not of ‘‘Hg sources of Hg deposition would obscure is relevant to EPA’s analysis of excess hotspots’’, which are often defined as the comparison of local and regional local deposition from U.S. EGUs high Hg concentration in fish, but rather U.S. EGU-attributable Hg deposition. because it is based on measurements of of Hg deposition hotspots, defined as Because of regional deposition from wet Hg deposition without excess local Hg deposition around U.S. both domestic and global sources of Hg, consideration of dry Hg deposition, EGUs, as clarified in the new Local total Hg deposition at any location is which can be a significant component of Deposition TSD. Because EPA did not unlikely to be highly correlated with Hg deposition. identify ‘‘Hg hotspots’’ of high Hg local sources. The EPA’s analysis The EPA disagrees with the concentrations in fish, the EPA’s MeHg focused on U.S. EGU-attributable Hg commenter regarding the interpretation water quality criterion of 0.3 mg/kg is deposition and demonstrates that for of the literature related to the spatial irrelevant to EPA’s analysis of excess some plants (especially those with high extent of deposition of Hg emitted by local Hg deposition for this rule. Hg emissions), there is local deposition U.S. EGUs. The EPA also disagrees that The EPA disagrees that the analysis of Hg that exceeds the average regional the peer-reviewed CMAQ model has assumes that deposition of Hg is deposition around the plant. limitations for this application or confined to a 50-km radius around The EPA’s analysis shows overestimates local deposition. The power plants. The purpose of the EPA’s heterogeneity in the amount of excess commenter does not provide any analysis was to evaluate whether there local deposition around plants. The new credible support for the assertion that existed ‘‘excess deposition of Hg in Local Deposition TSD shows that some grid-based models typically nearby locations within 50 km of EGUs plants can have local deposition that is overestimate local deposition that might result in Hg deposition less than the regional average surrounding EGUs. The EPA maintains ‘hotspots’.’’ As explained further in the deposition, suggesting that most of the that the CMAQ photochemical model new TSD, the EPA calculated the Hg from those plants is transported represents the best science currently regionally or that other EGUs in the available in simulating atmospheric 132 Edgerton et al., 2006. vicinity of those plants dominate the 133 Driscoll et al., 2007. deposition of Hg near the plants. This 134 EPRI, 2010.

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chemistry, transport, and deposition unable to account for the dynamics of commenter, the METAALICUS study processes. ecosystems that affect Hg shows that there is a lag time (and a The study 135 cited by the commenter bioaccumulation in fish, cannot non-proportional response) after 3–4 to support the notion that 91 to 96 consider non-air Hg inputs to years. The same commenter noted that percent of Hg emitted from power plants watersheds, and assumes reductions in there are numerous factors that travels beyond 50 km is based on a airborne Hg lead to proportional influence lag time including (1) photochemical transport model (the reductions in fish MeHg concentrations. watershed characteristics,140 (2) the fact TEAM model) that does not employ Another commenter claimed that data that watersheds may act as legacy current state-of-the-science and is not that demonstrate a steady-state linear sources releasing Hg when disturbed,141 actively developed or updated. reduction in fish tissue MeHg in (3) the magnitude of emission Furthermore, the modeling is based on response to a reduction in atmospheric reductions and subsequent changes in grid cells that are 20 km in size, which Hg deposition within watersheds do not atmospheric deposition need to be limits generalizability to EPA modeling exist and provided several references weighed against the amount of Hg performed at 12 km grid resolution that they claimed show non-linear already in an ecosystem,142 (4) the using a state of the science responses to changes in Hg distance of an ecosystem from Hg photochemical grid model. The cited deposition.137 138 sources,143 and (5) the fact that Hg modeling study ignores dry deposition The same commenter disagreed with deposited to aquatic ecosystems of elemental Hg from all sources, an EPA’s interpretation of Figure 2–17 in becomes less available for uptake by assumption that clearly limits the the March TSD and stated that a U.S. biota over time.144 Another commenter regional impacts from sources.136 The Geological Survey national waterway stated that additional Mercury Maps methodology of this study cited by the study 139 showed that sheet flow and assumptions do not allow for commenter is critically flawed in that it drainage, not deposition, dominated considerations of lag in response to presents no results where individual Hg input to the waterbodies it surveyed. changes in: (1) Deposition, (2) legacy emission sources are removed and the The commenter stated that sheet flow sources of Hg such as mining, (3) difference between the zero out and drainage could contain Hg and thus historical Hg deposition, (4) natural Hg simulation (where emissions from U.S. complicate the relationship that EPA levels in fish, (5) ecosystem dynamics EGUs are set to zero) and the baseline asserts is linear and direct. Another over time, or (6) the relative source model simulations are directly commenter cited Figure 2–17 in the Hg contributions over time. Another compared. Finally, the modeling study Risk TSD as showing that there is no commenter stated that lag times need to cited by the commenter presents an well-defined relationship between Hg be included in the modeling and be able illustration of gridded total annual Hg deposition and MeHg concentrations in to vary from watershed to watershed deposition from the TEAM model for fish tissue on a national basis. and sometimes even from waterbody to Several commenters provided the eastern U.S. that clearly shows waterbody within a watershed. Several comments related to the assumption elevated annual total Hg deposition in commenters stated that the emission that fish tissue Hg levels used in the the vicinity of coal-fired power plants in rates of Hg due to U.S. sources have analysis represent a steady-state. One the Ohio River Valley and northeast been decreasing for more than a decade, commenter stated that given the Texas. while emissions due to sources outside demonstrated lag time in response to the U.S. have been increasing. For this d. Hg Risk TSD deposition change, it is logical to reason, the commenter asserted that the 1. Assumption of Linear Proportionality conclude that a lag time needs to be system is not at steady-state, a basic in Relationship Between Changes in Hg incorporated in Mercury Maps to adjust premise of the model. Another Deposition and Changes in Fish Tissue the estimation of how much fish tissue commenter stated that while the time Hg Concentrations (Mercury Maps) MeHg levels decrease in response to lag for deposition to reach a waterbody decreases in Hg deposition attributable Comment: Several commenters is mentioned in the Hg Risk TSD, there to U.S. EGUs. According to the same criticized EPA’s assumption that is no discussion of the fact that a changes in deposition resulting from U.S. EGU emissions of Hg will result in 137 Harris., R.C., John W.M. Rudd, Marc Amyot, Christopher L. Babiarz, Ken G. Beaty, Paul J. 140 Grigal D.F., 2002. ‘‘Inputs and Outputs of proportional changes in fish tissue Hg Blanchfield, R.A. Bodaly, Brian A. Branfireun, Mercury from Terrestrial Watersheds: A Review,’’ concentrations at the watershed level, as Cynthia C. Gilmour, Jennifer A. Graydon, Andrew Environmental Review, 10, 1–39. supported by the Mercury Maps Heyes, Holger Hintelmann, James P. Hurley, Carol 141 Yang H., Rose N.L., Battarbee R.W., Boyle J.F., modeling exercise. According to one A. Kelly, David P. Krabbenhoft, Steve E. Lindberg, 2002. ‘‘Mercury and Lead Budgets for Lochnagar, a Robert P. Mason, Michael J. Paterson, Cheryl L. Scottish Mountain Lake and Its Catchment,’’ commenter, the Mercury Maps model Podemski, Art Robinson, Ken A. Sandilands, Environmental Science & Technology, 36, 1383– has limited capability to adequately George R. Southworth, Vincent L. St. Louis, and 1388. determine bioaccumulation in fish. The Michael T. TateRudd, J. W.M., Amyot M., et al., 142 Krabbenhoft D.P., Engstrom D., Gilmour C., same commenter stated that the Whole-Ecosystem study Shows Rapid Fish-Mercury Harris R., Hurley J., Mason R., 2007. Monitoring and Response to Changes in Mercury Deposition. Evaluating Trends in Sediment and Water Mercury Cycling Model (MCM) Proceedings of the National Academy of Sciences Indicators. In Harris R., Krabbenhoft D., Mason R., developed by EPRI is a more rigorous Early Edition, PNAS 2007 104 (42) pp. 16586– Murray M.W., Reash R., Saltman T. (Eds.), model that was developed expressly to 16591; (published ahead of print September 27, Ecosystem Responses to Mercury Contamination: evaluate the relationship between 2007). Indicators of Change. New York: Society of changes in atmospheric Hg deposition 138 Orihel D.M., Paterson M.J., Blanchfield P.J., Environmental Toxicology and Chemistry (SETAC) Bodaly R.A., Gilmour C.C., Hintelmann H., 2007. North America Workshop on Mercury Monitoring to waterbodies and changes in fish ‘‘Temporal Changes in the Distribution, and Assessment, CRC, pp. 47–87. tissue MeHg levels. Methylation, and Bioaccumulation of Newly 143 Lindberg S. et al. 2007. ‘‘A synthesis of Several commenters stated that the Deposited Mercury in an Aquatic Ecosystem,’’ progress and uncertainties in attributing the sources Mercury Maps model has many Environmental Pollution, 154, 77–88. of mercury in deposition.’’ Ambio 36(1): 19–32. deficiencies. Those commenters stated 139 Scudder B.C., Chasar L.C., Wentz D.A., Bauch 144 Orihel D.M., Paterson M.J., Blanchfield P.J., N.J., Brigham M.E., Moran P.W., Krabbenhoft D.P., Bodaly R.A., Hintelmann H., 2008. ‘‘Experimental that Mercury Maps is a static model 2009. Mercury in fish, bed sediment, and water Evidence of a Linear Relationship between from streams across the United States, 1998–2005: Inorganic Mercury Loading and Methylmercury 135 Seigneur et al., 2006. U.S. Geological Survey Scientific Investigations Accumulation by Aquatic Biota,’’ Environmental 136 Id. Report 2009–5109, 74 p. Science & Technology, 41, 4952–4958.

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portion of the deposition is unlikely to suggested by the commenter and had concentrations in fish tissue from that reach the water at all. the following response: watershed. The SAB agreed with this One commenter believes EPA The SAB agrees with the application of interpretation, noting the importance of incorrectly implied that its EGU risk Mercury Maps in this assessment. There are Figure 2–17 demonstrating that ‘‘spatial estimates using Mercury Maps are other modeling tools capable of making a variability of deposition rates is only underestimated because they do not national scale assessment, such as the one major driver of spatial variability of account for legacy EGU-attributable Regional Mercury Cycling Model (R–MCM). fish methylmercury and that variability deposition, which EPA assumes to be However, the R–MCM is more data intensive of ecosystem factors that control higher. and the results produced by the two model methylation potential (especially One commenter stated that while EPA approaches should be equivalent. wetlands, aqueous organic carbon, pH, The R–MCM, a steady-state version of the properly screened out watersheds with 151 time-dependent Dynamic Mercury Cycling and sulfate) also play a key role.’’ significant current non-air sources of Model, has been publicly available to and In response to recommendations from Hg, the EPA did not adequately screen used by the EPA (Region 4, Athens, the SAB, the EPA expanded the out watersheds with significant Hg Environmental Research Laboratory) for a discussion of uncertainties associated contributions from non-air sources, number of years. R–MCM requires more with the linearity assumption, including specifically watersheds with historic Hg detail on water chemistry, methylation uncertainties related to the potential for or gold mining or other industrial Hg potential, etc., and yields more information sampled fish tissue Hg level to reflect discharges. The same commenter stated as well. Substantial data support the Mercury previous Hg deposition and the that EPA’s study was not geographically Maps and the R–MCM steady-state results, so potential for non-air sources of Hg to balanced and was dominated by rivers that the results of the sensitivity analysis and contribute to sampled fish tissue Hg the outcomes from using the alternative levels. Each of these sources of in the coastal region of the southeast models would be equivalent between the two that has numerous wetlands, which are modeling approaches. Though running an uncertainty may result in potential bias favorable locations for methylation and alternative model framework may provide in the estimate of exposure associated have conditions that are not typical of additional reassurance that the Mercury with current deposition. The EPA took much of the rest of the U.S. Maps ‘‘base case’’ approach is a valid one, it steps to minimize the potential for these Response: The EPA disagrees with the is unlikely that substantial additional insight biases by (1) only using fish tissue Hg commenters who challenged the would be gained with the alternative model samples from after 1999, and (2) assumption of a linear proportional framework.146 screening out watersheds that either relationship between changes in U.S. In addition, the SAB stated, ‘‘Since contained active gold mines or had EGU deposition and fish tissue Hg the Mercury Maps approach was other substantial non-U.S. EGU levels. The EPA specifically asked the developed, several recent publications anthropogenic emissions of Hg. The SAB to evaluate EPA’s assumption of have supported the finding of a linear SAB commented that EPA’s approach to linear proportionality in the relationship between mercury loading minimizing the potential for these relationship between Hg deposition and and accumulation in aquatic biases to affect the results of the risk fish tissue MeHg concentrations, biota.147 148 149 These studies suggested analysis appears to be sound and that supported by the Mercury Maps that mercury deposited directly to additional criteria that could be applied analysis. The SAB peer review aquatic ecosystems can become quickly are unlikely to substantially change the committee provided the following available to biota and accumulated in results. As a result, the EPA disagrees overall response, which generally fish, and that reductions in atmospheric with the commenter that EPA’s supports EPA’s approach: mercury deposition should lead to screening process is inadequate. In The SAB agrees with the Mercury Maps decreases in methylmercury addition, we conducted several approach used in the analysis and has cited concentrations in biota. These results sensitivity analyses to gauge the impact additional work that supports a linear substantiate EPA’s assumption that of excluding watersheds with the relationship between mercury loading and proportionality between air deposition potential for non-EGU Hg emissions, accumulation in aquatic biota. These studies changes and fish tissue methylmercury and found that the results were robust suggest that mercury deposited directly to level changes is sufficiently robust for to these exclusions. aquatic ecosystems can become quickly In response to specific comments available to biota and accumulated in fish, its application in this risk 150 regarding the use of the Mercury Maps and reductions in atmospheric mercury assessment.’’ deposition should lead to decreases in Based on the responses of the SAB model, the EPA clarifies that the Hg methylmercury concentrations in biota. The peer review committee, the EPA’s use of Risk TSD did not directly use the SAB notes other modeling tools are available the linear proportionality assumption, Mercury Maps model. Instead, the EPA to link deposition to fish concentrations, but supported by the Mercury Maps applied an assumption of linear does not consider them to be superior for this analysis, is well-supported. proportionality between changes in Hg analysis or recommend their use. The The EPA also disagrees with deposition and changes in MeHg integration of Community Multiscale Air commenters’ interpretation of Figure 2– concentrations in fish that is supported Quality Modeling System (CMAQ) deposition by the Mercury Maps modeling. By modeling to produce estimates of changes in 17. As stated in the Hg Risk TSD, while fish tissue concentrations is considered to be this figure is useful to demonstrate the assuming steady-state conditions in sound. Although the SAB is generally lack of correlation across watersheds apportioning fish tissue Hg levels and satisfied with the presentation of between total deposition of Hg and risk, the EPA does not attempt to project uncertainties and limitations associated with MeHg concentrations in fish tissue, it is lag times. Recent research cited by the the application of the Mercury Maps not indicative of the likely correlation SAB 152 153 154 identifies relatively rapid approach in qualitative terms, it recommends between changes in Hg deposition at a response of fish tissue Hg to changes in that the document include quantitative Hg loading, which suggests that fish estimates of uncertainty available in the given watershed and changes in MeHg existing literature.145 tissue Hg levels could react more 146 U.S. EPA–SAB, 2011. The SAB peer review committee 147 Orihel et al., 2007. 151 U.S. EPA–SAB, 2011. specifically addressed the MCM 148 Orihel et al., 2008. 152 Orihel et al., 2007. 149 Harris et al., 2007. 153 Orihel et al., 2008. 145 U.S. EPA–SAB, 2011. 150 U.S. EPA–SAB, 2011. 154 Orihel et al., 2007.

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quickly to reductions in Hg deposition urban areas, which account for the Several commenters stated that HUC than previously thought. This finding majority of census tracts, because these watersheds are 35 km on a side. The reduces concern that fish tissue Hg census tracts are more likely to be commenters appear to be referring to levels could be linked to older patterns included in a risk analysis because they HUC8 classifications. The HUCs are of Hg deposition and strengthens the have more than 25 people living in defined for varying spatial resolutions. approach used in the revised Hg Risk poverty. The commenter stated that The geographic unit used as the basis TSD. While fish tissue may respond these census tracts may drive the for generating risk estimates is HUC12, rapidly to changes in Hg loading, this extremes of the distribution without which are watersheds about 10 km on does not change the fact that previously regard to the actual number of high- a side, which is comparable with the emitted Hg from U.S. EGUs can be re- level, self-caught fish consumers within size of the 12 km2 grid cells in CMAQ, emitted and re-deposited, and thus their boundaries. The commenter stated which are 12 km2. The EPA has also affect Hg concentration in fish. that they could not assess the potential clarified that the specific unit of bias and noted that EPA did not test the analysis for this assessment is at the 2. Characterization of Subsistence bias by sensitivity analyses. watershed, not enumerated Fishing Populations and Exposure Several commenters stated that EPA subpopulations. Scenario was not clear whether the poverty The EPA only used the U.S. Census Comment: Several commenters stated criteria were applied in all scenarios or tracts to determine whether there are that EPA provides no clear definition of just for the high-end female fish populations in the vicinity of a given subsistence, near subsistence, or high- consumer scenario. One commenter watershed, which could increase the end fish consumption, instead assuming stated that EPA should apply the potential for a category of subsistence that poverty is a direct indication of minimum 25 source population criteria fishers to be active at that watershed. In subsistence fishing and high-end fish only to populations of women of the revised Hg Risk TSD, the EPA consumption. One commenter stated no childbearing age. One commenter stated modified the female subsistence documentation exists to supports these that EPA’s assumption would result in scenario to apply equally to all assumptions. Another commenter stated any densely populated urban census watersheds with fish tissue Hg data that EPA’s definitions of subsistence tract with a single fish tissue sample based on the likelihood that these fishers in the Hg Risk TSD are not being assigned to a modeled watershed populations have the potential to fish at consistent with earlier EPA documents with populations potentially at-risk, most watersheds. As described in the and are used inconsistently throughout regardless of the actual degree of revised Hg Risk TSD, the EPA made this the Hg Risk TSD. Several commenters recreational or subsistence fishing change in response to SAB’s concerns stated that while subsistence fishing can taking place there. regarding the potential exclusion of be associated with poverty, poverty does Response: The EPA agrees with the watersheds with fewer than 25 not indicate subsistence fishing. One comments that subsistence fish individuals and regarding coverage for commenter stated that by including consumption was not clearly defined, high-end recreational fish watersheds with as few as 25 members and we have provided a clearer consumption.157 Thus, concerns of individuals living in poverty, the EPA definition in the revised Hg Risk TSD, regarding the use of census data to overstates risks. however, this clarification does not select watersheds with the potential for One commenter stated that it is result in any changes to the quantitative subsistence fishing no longer apply to unclear what literature the Agency says analysis. In the revised Hg Risk TSD, the this scenario. However, for the ‘‘generally supports the plausibility of EPA clarifies that ‘‘subsistence fishers’’ remaining subsistence scenarios, the high-end subsistence-like fishing * * * are defined as individuals who rely on EPA continues to use U.S. Census tract- to some extent across the watersheds’’ noncommercial fish as a major source of level data to evaluate the presence of a and stated that if other studies exist, the protein.155 This definition is reflected in ‘‘source population’’ in the vicinity of EPA should provide the values for the range of fish consumption rates used the watershed being modeled for risk. In comparison. in estimating risk. The likely presence this context, the EPA uses the U.S. One commenter stated that EPA of this type of subsistence fish consumer Census data to assess whether a combined two parameters with differing is supported by available peer reviewed socioeconomic status (SES)- scales to establish the geographic unit literature (see Table 1–5 of the revised differentiated group similar to the used in the Hg Risk TSD risk Hg Risk TSD). These studies clearly particular type of subsistence fisher assessment. The HUC watersheds are show that a subset of surveyed fishers being modeled (e.g., poor Hispanics) are based on average about 35 square miles consumes self-caught fish at the rates located in the vicinity of the watershed. in size, while U.S. census tracts used to cited in the Hg Risk TSD. The SAB peer If a source population is nearby, then identify watersheds relevant for review concluded that the consumption this increases the potential that subpopulations of interest—cover a few rates and locations for fishing activity subsistence fishing activity could occur tenths to hundreds of square miles. are supported by the data presented in for that population scenario. Several commenters stated that it is the Hg Risk TSD, and are generally The EPA continues to model risk for unclear how the analysis handled reasonable and appropriate given the white and black subsistence fishers differences in geographic resolution available data.156 active in the southeast and for Hispanics between watersheds and census tracts The EPA notes that there is some assessed nationally. In this case, the were. confusion in the comments related to EPA links poverty with subsistence One commenter stated that the the size of the watersheds modeled. fishing, as EPA only modeled locations procedure for assigning census tracts with poor source populations. However, could bias exposure outcomes. For 155 U.S. EPA, U.S. Environmental Protection in modeling these three populations, the example, the commenter stated that a Agency. 2000. Guidance for Assessing Chemical single influential census tract in a Contaminant Data for Use in Fish Advisories, 157 This change led to a very small increase in the watershed could drive risk, even if the Volume 3: Overview of Risk Management. Office of number of watersheds with populations potentially Science and Technology, Office of Water, U.S. at-risk. In the Hg Risk TSD accompanying the watershed had only a minimal number Environmental Protection Agency, Washington, DC proposed rule, approximately 4 percent of modeled of fish samples. The commenter stated EPA 823–B–00–007. watersheds were excluded based on the SES-based that this possibility is a concern in 156 U.S. EPA–SAB, 2011. filtering criteria.

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EPA asserts that the presence of a poor according to one commenter, increases lake trout). This study 166 provides a source population indicates the estimated intake by 50 percent, thus range of adjustment factors for each fish potential for subsistence fishing activity, increasing the daily MeHg intake rate by type including 1.1 to 1.5 for walleye and rather the presence of such activity. The a constant factor of 33 percent and also 1.5 to 2.0 for lake trout. Given these two linkage between poverty and higher increasing any resulting (HQ) risk ranges, the EPA determined it to be rates of subsistence fish consumption is estimate by a similar factor. Several reasonable to take an intermediate value supported by the Burger et al. study,158 commenters stated that the source of between the two ranges (i.e., 1.5), rather which identified substantially higher EPA’s selected loss factor 159 reported a than focus on either the highest or consumption rates for poor individuals range of cooking losses from 1.1 to 6. lowest values, which is not the most (see Table 5 of the study). The EPA Several commenters cite several studies conservative assumption that the EPA acknowledges that subsistence fishing that report no or highly variable changes could have made. This study 167 also activity by specific subpopulations in MeHg levels as a result of cooking explains that preparation/cooking of might only be present across a subset of fish.160 161 162 163 164 One commenter fish results in an increase in MeHg the watersheds EPA modeled for risk. suggested that EPA’s cooking loss levels per unit fish because Hg However, given the stated goal of the adjustment factor of 1.5 is at the high- concentrates in the muscle, while analysis to determine the percent of end of the values supported by the preparation/cooking tends to reduce watersheds where the potential exists literature. Another commenter stated non-muscle elements (e.g., water, bone, for exposures to U.S. EGU-attributable that EPA has used other adjustment fat). Hg to represent a public health hazard, factors in previous documents, and that Regarding the alternative studies identifying a set of watersheds with the the adjustment factor should not be identified by the commenters, the EPA potential for the type of high fish fixed across different populations given disagrees that these studies considered consumption that leads to high Hg potential differences in cooking collectively contradict the cooking loss exposure is appropriate. The EPA notes practices. Several commenters noted factor in the analysis. Specifically, the that relatively few watersheds (less than that the cooking loss adjustment factor first study 168 may have included 4 percent) have fish tissue Hg data, and, should only be applied to estimates of measurement of non-fish components thus, can be included in the risk consumption rates for prepared fish, added to dishes (e.g., onions, heavy assessment. Consequently, while there and that some sources of consumption breading etc.), which could dilute the is the potential for including some rates are based on raw fish. post-cooking Hg measurements and give watersheds in the analysis that may not the appearance of a cooking loss even as have currently active subsistence fishing Response: The EPA disagrees with the commenters that the selection of the actual fish tissue Hg levels could have activity, it is likely that EPA excluded 169 cooking loss factor of 1.5 is not justified increased. In the second study, the other watersheds from the analysis fish species are saltwater and not where this type of subsistence fishing by the literature. The EPA also disagrees with the comment that the cooking loss freshwater, and the authors note that the activity occurs due to a lack of fish reduction of water and fat could tissue Hg data. adjustment factor of 1.5 is at the high- end of the range of values in the increase in the Hg concentration While EPA agrees with the comment without changing absolute content. The that it is likely that exposure to total literature. The EPA selected the Morgan study 165 as the basis for the food third study focused on measurement of MeHg through commercial fish bioaccessible Hg in raw and cooked consumption represents a more preparation/cooking adjustment factor fish.170 However, available information significant risk for the general because it focused on the types of currently allows us to specify the risk population than consumption of freshwater fish species representative of model in terms of total Hg intake, not freshwater fish obtained through self- what might be consumed by subsistence bioaccessible Hg, thus, this article is caught fishing activity, exposure to total fishing populations (i.e., walleye and potentially informative for guiding MeHg through self-caught fish future research and methods consumption is the most significant risk 159 Morgan, J.N., M.R. Berry, and R.L. Graves. development, not the current risk for subsistence fishing populations and 1997. ‘‘Effects of Commonly Used Cooking Practices on Total Mercury Concentration in Fish and Their assessment. The fourth study 171 found high-end recreational fishers. For the Impact on Exposure Assessments.’’ Journal of a modest but statistically insignificant subset of these populations that focus Exposure Analysis and Environmental increase in Hg levels for most of the their fishing activity in freshwater Epidemiology 7(1):119–133. streams and lakes, it is also the case that 160 Armbruster G., Gerow K.G., Lisk D.J., 1988. cooking methods assessed, which is they will experience a higher fraction of ‘‘The Effects of Six Methods of Cooking on Residues directionally consistent with EPA’s of Mercury in Striped Bass,’’ Nutrition Reports MeHg exposure attributable to U.S. EGU cooking loss adjustment. The fifth International, 37, 123–126. study 172 only addressed the issue Hg emissions. As a result, the EPA 161 Gutenmann, W.H. and Lisk D.J., 1991. ‘‘Higher qualitatively, thus cannot be used for focused the risk assessment on Average Mercury Concentration in Fish Fillets after subsistence fishers active at inland Skinning and Fat Removal,’’ Journal of Food Safety, the cooking loss factor. When 11, 99–103. considered collectively, the EPA freshwater watersheds because they are 162 likely to experience the highest levels of Farias L.A., Favaro, D.I., Santos J.O., disagrees that the additional studies Vasconcellos M.B., et al., 2010. ‘‘Cooking Process identified by the commenter contradict individual risk as a result of exposure to Evaluation on Mercury Content in Fish,’’ Acta U.S. EGU-attributable Hg. Amazonia, 40 (4), 741–748. the cooking loss factor used in the risk 163 Perello´ G., Martı´-Cid R., Llobet J.M., Domingo assessment and maintains that the 3. Cooking Loss Adjustment Factor J.L., 2008. ‘‘Effects of Various Cooking Processes on Morgan study 173 remains the most Comment: Several commenters stated the Concentrations of Arsenic, Cadmium, Mercury, and Lead in Foods,’’ Journal of Agricultural and 166 Id. that EPA did not justify the selection of Food Chemistry, 156 (22), 11262–11269. 167 Id. a cooking loss factor of 1.5 that, 164 Torres-Escribano S., Ruiz A., Barrios L., Ve´lez 168 Farias et al., 2002. D., Montoro R., 2011. ‘‘Influence of Mercury 169 Perello´ et al., 2008. 158 Burger, J., 2002. ‘‘Daily Consumption of Wild Bioaccessibility on Exposure Assessment 170 Torres-Escribano et al., 2011. Fish and Game: Exposures of High End Associated with Consumption of Cooked Predatory 171 Recreationists,’’ International Journal of Fish in Spain,’’ Journal of the Science of Food and Armbruster et al., 1988. Environmental Research and Public Health, 12 (4), Agriculture, 91 (6), 981–6. 172 Gutenmann et al., 1991. 343–54. 165 Morgan et al., 1997. 173 Morgan et al., 1997.

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applicable for characterizing cooking/ percentile distribution estimates. for the risk assessment, especially at the preparation effects on Hg concentrations Another commenter stated that EPA’s tails of the distribution. The commenter in fish. use of the 99th percentile fish stated that the table does not include a The EPA agrees that application of the consumption for its risk analysis is median statistic and does not provide cooking loss adjustment factor is inconsistent with the Agency’s risk any information on the number of lakes appropriate if the fish consumption assessment guidelines, which and river segments in each watershed. rates are for as cooked or as consumed recommend evaluating a reasonable According to the commenter, an and not for raw fish. Careful review of maximum exposure (‘‘RME’’) analysis of EPA’s database by the SAB the three studies used in the risk scenario,181 which equates to about a indicated that 60 percent of the assessment to identify subsistence fisher 95th percentile fish consumption value. watersheds with fish Hg data from rivers consumption rates suggests that all three The same commenter stated that EPA have risks calculated based upon a represent annual-average daily intakes applied the 99th percentile to a ‘‘small sample size of one or two fish. The (g/day) of as consumed or as cooked survey of 149 South Carolina female commenter stated that it is not fish. One study stated that they used anglers’’ to calculate an ingestion rate of reasonable to base a significant policy models of portion or meal size servings 373 grams per day (g/day). The and regulation decision on watersheds (the size of the serving the respondent commenter stated that if the 95th where exposure is based on a single fish regularly eats).174 Therefore, the EPA percentile is used the ingestion rate sample in a single water body within it. interprets the fish consumption rates would be 173 g/day and if the default Several commenters criticized EPA’s provided in this study 175 as ingestion rate for determining ambient use of the 75th percentile fish tissue representing as cooked/prepared and water standards is used the ingestion MeHg level in a watershed. One not for raw fish and for that reason, rate would be 142 g/day. commenter stated that EPA provided no application of a preparation/cooking Several commenters stated that EPA rationale for its decision to choose the adjustment factor is required. Another based its fish consumption rates used in highest of the 75th percentile for fish Hg study 176 used different sized models of the risk analysis on a limited number of levels among rivers and lakes within the cooked fish filets and therefore these studies and that those studies are poorly HUC. Several commenters stated that consumption rates are also interpreted documented. subsistence fishers are less likely to as represented as cooked/prepared and Another commenter stated that EPA target larger fish relative to recreational not raw fish. One study 177 178 queried should summarize available supporting fishers. Several commenters suggested survey responders for meal portion or studies by basic study content, that EPA include a sensitivity analysis serving size and therefore, the characteristics, design, size, using the mean or median fish MeHg consumption rates do represent as demographics, dietary recall period, and level in a watershed. One commenter cooked/prepared. Because all three fish intake rates by demographic also stated that EPA arbitrarily inflated studies provide consumption rates variables. According to the commenter, the risk estimates by assuming based on as cooked/prepared or as this summary would support the consumption of only fish greater than 7 consumed, it is appropriate to apply the scientific validity of the assessment and inches and choosing the largest of the cooking loss adjustment factor in better illustrate the potential variability 75th percentile of fish Hg levels from modeling exposure. and uncertainty involved in these larger fish (i.e., larger than 7 inches) for rivers and lakes. That same 4. Fish Consumption Rates and Fish extrapolating data from small commenter suggested using the median Tissue Hg Characterization populations to the national-scale. The commenter also noted that the three of all size fish, not just those over 7 Comment: One commenter stated that studies actually used to provide inches. in the past the Agency has subsistence population estimates, which One commenter stated that EPA recommended various default were extrapolated to the national-scale, should quantify adverse effects from the consumption rates (in the general range included a limited number of ingestion of MeHg in seafood in of 130 to <150 g/day) to provide default individuals living in diverse and addition to ingestion of MeHg from self- intakes for subsistence fishers under the localized areas. caught freshwater fish. According to the Risk Assessment Guidance for One commenter stated that the commenter, recent studies demonstrate Superfund (RAGS) or the Fish Advisory assumption with the greatest impact on that were EPA to take into account Guidance.179 180 The commenter stated risk is the fish consumption rate. That consumption of seafood, MeHg that these default consumption rates are same commenter stated that using 99th consumption in the U.S. is of even derived from various studies and percentile ingestion rate dramatically greater concern. generally are based on 90th or 99th increases HQ and IQ loss compared to Response: The EPA acknowledges the 50th percentile ingestion rate. The that the focus of the Hg Risk TSD is 174 Burger et al., 2002. commenter stated that when an estimate characterizing risk for the groups likely 175 Id. of the 95th percentile ingestion rate of to experience the greatest U.S. EGU- 176 Shilling, Fraser, Aubrey White, Lucas Lippert, attributable Hg risk, which are Mark Lubell (2010). Contaminated fish the 15 to 44 year old female population consumption in California’s Central Valley Delta. is considered, the HQ is a tenth of the subsistence fishing populations active at Environmental Research 110, p. 334–344. value computed with the 99th inland freshwater lakes and rivers. 177 Dellinger JA. 2004. ‘‘Exposure assessment and percentile high-end female fisher. Specifically, within that subsistence initial intervention regarding fish consumption of One commenter stated that EPA fishing population, the EPA is interested tribal members of the Upper Great Lakes Region in in those individuals who are most at- the United States.’’ Environ Res 95:325–340. provides broad summary statistics of its 178 Personal communication, Dr. Dellinger, fish tissue data in Table 5–2 of the risk, which includes those who September 27, 2011. Regulatory Impact Analysis (RIA), but consume the most fish. For that reason, 179 U.S. EPA. 1991. Risk Assessment Guidance for the summary does not allow an the EPA considered a range of high-end Superfund (RAGS). Part C 1991 EPA/9285.7–01C. assessment of the representativeness fish consumption rates including the October. 99th percentile representing the most 180 U.S. EPA. 2000. National Guidance: Guidance and robustness of the underlying data for Assessing Chemical Contaminant Data for Use highly-exposed individuals. In in Fish Advisories, Volume 2. EPA 823–B–00–008, 181 U.S. EPA. 1989. Risk Assessment Guidance for responding to the SAB peer review, the November. Superfund (RAGS). EPA/540/1–89/002. December. EPA clarified this focus in the

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introduction to the revised Hg Risk TSD studies.183 184 185 186 187 Several studies subsistence fisher groups, and in several and changed the full title to revised identified additional fishing cases the EPA did not use the 99th Technical Support Document: National- populations with subsistence or near percentile consumption rates because Scale Assessment of Mercury Risk to subsistence consumption rates, the sample sizes were too low to Populations with High Consumption of including urban fishing populations support this level of resolution. This Self-caught Freshwater Fish. (including low-income decision did not affect EPA’s finding of The EPA agrees that the fish populations),188 189 190 Laotian a hazard to public health, which is consumption rate is an important factor communities,191 and Hispanics. The based on the results for the female in calculating risk from exposure to EPA participated in 1999 in a project subsistence fishing population, which MeHg in fish. The EPA acknowledges investigating exposures of poor, has an estimate of the 99th percentile that the distribution of fish minority communities in New York City consumption rate that is supported by consumption rates is positively skewed, to a number of contaminants including an adequate sample size. which means that at higher percentiles Hg, which found these populations can The EPA disagrees with the comment (e.g., 90th, 95th, and 99th) there is a have very high fish consumption that it did not provide a rationale for substantial increase in ingestion rates rates.192 The SAB concluded that the choosing the 75th percentile fish tissue relative to the mean or median. The consumption rates and locations for concentration across lakes and rivers in revised Hg Risk TSD includes a fishing activity are supported by the a watershed. However, the EPA reasonableness check on the amount of data presented in the Hg Risk TSD, and modified the methodology based on fish consumed (as a daily value) are generally reasonable and appropriate evaluation of the number of samples reflected in the different rates. While the given the available data.193 within each watershed (responding to a 99th percentile consumption rates for The EPA agrees that the Hg Risk TSD recommendation from the SAB). In the the subsistence female fisher (373 g/day) would be improved by clarifying that revised methodology, the EPA computes is substantially higher than the 90th or the literature review focused on the 75th percentile value at each 95th percentile values (123 and 173 g/ identifying studies that characterize sampling site within a watershed. The day respectively), the 99th percentile subsistence fish consumption for groups EPA then computed the average of the value translates into a 13-ounce meal. active at freshwater locations within the site-specific 75th percentile fish tissue While this represents a large serving, it U.S., and EPA has revised the Hg Risk Hg values within a given watershed. is still reasonable if representing an TSD accordingly. In the Hg Risk TSD, This approach does not differentiate individual who receives all of their meat the EPA summarized important study between rivers and lakes and reflects an protein from self-caught fishing, and the attributes for the source studies used to improved treatment of behavior, 13 ounces per day do not have to be obtain fish consumption rates. This allowing for fishers to choose among eaten all at one meal. The higher information was provided in Table C–1 multiple fishing sites within a consumption rates (i.e., greater than 250 in an appendix. To improve clarity, the watershed. g/day) are supported by all three studies EPA moved the summary table to the The EPA generally agrees with the used in the risk assessment, and main body in the revised Hg Risk TSD. comment that some fraction of therefore, there is support across studies In identifying these studies, the EPA subsistence fishers likely consume fish near the upper bound of likely focused on surveys for subsistence without consideration for size (given consumption rates in this range. The fishers that were applicable at the dietary necessity), however, the EPA EPA acknowledges uncertainty broader regional or national level. In the considers it reasonable to assume that a associated with estimating high-end Hg Risk TSD, the EPA acknowledged subset of subsistence fishers could target percentile values in these studies due to the smaller sample sizes for some of the larger fish in order to maximize the relatively low sample sizes for some potential consumption per unit of population groups. However, even if a 183 Burger, J., K. Pflugh, L. Lurig, L. Von Hagen, fishing effort. The EPA uses this subset few individuals reported these high self- and S. Von Hagen. 1999a. ‘‘Fishing in Urban New of subsistence fishers targeting larger Jersey: Ethnicity Affects Information Sources, fish, which is represented by the 75th caught fish consumption rates, making Perception, and Compliance.’’ Risk Analysis 19(2): it difficult to characterize the 217–229. percentile fish tissue value, in the risk population percentiles they represent, 184 Burger, J., Stephens, W. L., Boring, C. S., assessment. In addition, including the the values still suggest that these levels Kuklinski, M., Gibbons, J. W., Gochfeld M. 1999b. female subsistence fishing population in of high fish consumption exist among ‘‘Factors in Exposure Assessment: Ethnic and the analysis also provides coverage for Socioeconomic Differences in Fishing and surveyed individuals. To determine Soncumption of Fish Caught along the Savannah high-end recreational anglers who target whether a public health hazard could River.’’ Risk Analysis, Vol. 19, No. 3, p. 427. larger freshwater fish. The SAB exist, the EPA asserts that it is 185 California Environmental Protection Agency commented that: ‘‘Using the 75th reasonable to include these (CalEPA). 1997. Chemicals in Fish Report No. 1: percentile of fish tissue values as a Consumption of Fish and Shellfish in California reflection of consumption of larger, but consumption rates as representative of and the United States Final Draft Report. Pesticide the most at-risk populations. In these and Environmental Toxicology Section, Office of not the largest, fish among sport and cases, however, the EPA acknowledges Environmental Health Hazard Assessment, July. subsistence fishers is a reasonable that it is important to highlight 186 Tai, S. 1999. ‘‘Environmental Hazards and the approach and is consistent with uncertainty associated with Richmond Laotian American Community: A Case published and unpublished data on Study in Environmental Justice.’’ Asian Law Journal predominant types of fish characterizing the specific population 6: 189. 194 percentile that these ingestion rates 187 Corburn, J. 2002. ‘‘Combining community- consumed.’’ The SAB suggested that represent, and EPA has done so in the based research and local knowledge to confront EPA include a sensitivity analysis based revised Hg Risk TSD. asthma and subsistence-fishing hazards in on use of the median value, and EPA The EPA disagrees with the comment Greenpoint/Williamsburg, Brooklyn, New York.’’ has done so in the revised Hg Risk TSD. that high consumption rates are poorly Environmental Health Perspectives 110(2). This sensitivity analysis showed that 188 Burger et al., 1999a. documented. Evidence of these high fish 189 Burger et al., 1999b. using the median estimates had only a consuming populations can be found in 190 CalEPA, 1997. small impact on the number and percent surveys 182 and specialized 191 Tai, 1999. of modeled watersheds with 192 Corburn, 2002. 182 Burger et al., 2002. 193 U.S. EPA–SAB, 2011. 194 U.S. EPA–SAB, 2011.

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populations potentially at-risk from U.S. flawed Faroe Islands’ children study One commenter stated that a study by EGU-attributable MeHg exposures. In and ignored the Seychelles Islands Texas Department of State Health the revised Hg Risk TSD, the EPA study,198 which did not confirm any Services (DSHS, 2004) 201 determined clarified that the 7-inch cutoff harm on children due to MeHg that among subsistence fishers who eat represents a minimum size limit for a exposure. According to the commenters, fish from Caddo Lake with elevated number of key edible freshwater fish application of the Faroe Island study is MeHg, women of child-bearing years species established at the State-level. suspect because (1) the raw data from did not have blood Hg levels greater For example, Pennsylvania establishes 7 the study have never been made than the RfD. Thus, according to the inches as the minimum size limit for available for independent analysis and commenter, the connection between both trout and salmon (other edible fish scrutiny, (2) there is potential for MeHg in fish and adverse health effects species such as bass, walleye and confounding by polychlorinated in the U.S. is not fully understood and northern pike have higher minimum biphenyls (PCBs) and lead, (3) could involve other factors, including size limits).195 population exposure to MeHg was the protective effects of fatty acids and The EPA disagrees with the comment through consumption of highly selenium in fish, which EPA did not that it is not reasonable to use contaminated pilot whale meats and taken into account. watersheds where only a single fish blubbers, and (4) exposure levels in the Two commenters claim that EPA uses sample is available. Although it is U.S. remain lower than those observed the RfD as if it were an absolute generally preferred to have multiple in the primary study. One commenter threshold for health risk in the risk samples, the SAB noted that using a also notes that (1) Seychelles Islanders assessment even though the RfD single sample is likely to underestimate consume far more fish than Americans methodology is a screening tool for the 75th percentile fish MeHg do; (2) the amount of MeHg in the U.S. deciding when risks clearly do not exist. concentration and is, therefore, likely to population is much lower than the Several commenters recommended underestimate the risk estimates for Seychelles Islanders; and (3) all ocean adding qualitative discussions to the Hg those watersheds. The SAB suggested fish contain about the same amount of Risk TSD regarding several aspects of that EPA conduct additional analyses of MeHg, so MeHg intake per fish meal is uncertainty, including uncertainty in the fish tissue MeHg data, which EPA similar between Americans and the RfD, uncertainty in extrapolating a has done and included in the revised Hg Seychelles Islanders. However, another dose-response relationship between Risk TSD. The revised Hg Risk TSD commenter stated that industry MeHg exposure and change in IQ, includes information on the number of arguments against using the Faroe uncertainty in extrapolating the dose- watersheds modeled in the risk Islands study fail to acknowledge that response relationship from marine fish assessment with various fish tissue Hg the study results were consistent with and marine mammals to freshwater fish, samples sizes (e.g., 1, 2, 3–5, 6–10 and studies in the Seychelles Islands, New and uncertainty due to potential >10 measurements). Zealand,199 and Poland.200 confounding by PCBs in marine species. One commenter criticized EPA for Several commenters raised concerns 5. Reference Dose (RfD) for MeHg and regarding the relationship between Hg Health Effects Studies using a linear dose-response model for the RfD-based HQ metric and the IQ MeHg exposure and IQ loss. Two Comment: Several commenters stated metric. Another commenter stated that commenters stated that changes in IQ 196 that EPA’s RfD is based on sound the RfD assumes a threshold dose below are not a well-defined health science, which was supported by the which an appreciable risk of adverse consequence of MeHg exposure. One 197 findings of the NAS Study, and that effects is unlikely, and NAS did not commenter stated that the SAB had EPA appropriately applied the RfD in evaluate whether MeHg exposure data reservations about EPA’s use of IQ loss. the Hg risk assessment. The commenters were better fit by a linear or non-linear Two commenters questioned whether also stated that recent studies find clear model or by a threshold or non- IQ impacts would even occur because in associations between maternal blood Hg threshold model. Japan and Korea, where the maternal levels and delayed child development Several commenters stated that EPA’s blood Hg levels are higher than in the and cardiovascular effects, as well as MeHg RfD is more conservative than U.S., there is no evidence of adverse potential for effects due to exposure to ‘‘safe’’ levels determined by other effects. Another commenter cited a 202 pollutant mixtures including lead. federal agencies and claim that EPA study that found verbal IQ scores for However, many commenters assigned unusually high uncertainty children from mothers with no seafood expressed concerns regarding EPA’s use factors. Several commenters stated that intake were 50 percent more likely to be of the MeHg RfD as a benchmark for EPA’s use of the 1999 National Health in the lowest quartile. One commenter health risk. Several commenters raised and Nutrition Examination Survey questions using an IQ risk metric concerns claiming that EPA has not (NHANES) blood Hg levels show a threshold of >1 or >2 points because incorporated the best available Hg downward trend since 1999, and the variation in IQ measures and the intra- toxicological data into the RfD, which levels have been below the RfD since individual variation in IQ are higher results in a flawed analysis and an 2001. than the threshold. overestimate of the impact of Hg Several commenters question the emissions on human health. relationship between cardiovascular 198 Budtz-Jorgensen E, Debes F, Weihe P, Several commenters stated that, when Grandjean P. 2005. ‘‘Adverse Mercury Effects in 7– effects and MeHg exposure. Two deriving the RfD, the EPA relied on the Year-Old Children Expressed as Loss in ‘‘IQ’’.’’ EPA–HQ–OAR–2002–0056–6046. 201 DSHS. 2005. Health Consultation: Mercury 195 Pennsylvania Fish and Boat Commission. 199 Kjellstrom, T; Kennedy, P; Wallis, S; et al. Exposure Investigation Caddo Lake Area-Harrison 2011. Summary Book: 2011 Pennsylvania Fishing 1986. Physical and mental development of children County Texas. Agency for Toxic Substances and Laws & Regulations available at: http:// with prenatal exposure to mercury from fish. Stage Disease Registry. http://www.tceq.state.tx.us/assets/ fishandboat.com/fishpub/summary/inland.html. 1: Preliminary test at age 4. Natl Swed Environ public/comm_exec/pubs/sfr/085.pdf. 196 U.S. Environmental Protection Agency— Protec Bd, Rpt 3080 (Solna, Sweden). 202 Hibbeln JR, Davis JM, Steer C, Emmett P, Integrated Risk Information System (U.S. EPA– 200 Wieslaw Jedrychowski et al. 2006. ‘‘Effects of Rogers I, Williams C, et al., 2007. ‘‘Maternal seafood IRIS). 2001. Methylmercury (MeHg) (CASRN Prenatal Exposure to Mercury on Cognitive and consumption in pregnancy and 22967–92–6). Available at http://www.epa.gov/iris/ Psychomotor Function in One-Year-Old Infants: neurodevelopmental outcomes in childhood subst/0073.htm. Epidemiologic Cohort Study in Poland,’’ 16 Annals (ALSPAC study): an observational cohort study. ’’ 197 NAS, 2000. of Epidemiology 439. Lancet 369:

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commenters cited studies examining the IRIS process 212 advised strongly against The EPA disagrees that the relationship between MeHg exposure using results from a study that at the uncertainty factor is ‘‘unusually high’’. and cardiovascular time had not shown an association The uncertainty factor used in effects,203 204 205 206 207 208 but concluded between MeHg exposure and adverse calculation of EPA’s peer-reviewed RfD that it seems premature to use these effects. Further, the EPA disagrees with is small (10 fold); half of this factor is studies to establish a dose-response comments stating that EPA based the to account for measured variability in relationship. MeHg RfD solely on results from the human pharmacokinetics, which is Several commenters assert that the Faroe Islands population and disagrees based on advice of the NAS 217 and an risks from eating seafood are low that the information underlying the RfD independent panel of scientific peer relative to the benefits, that fish is ‘‘poorly explained’’. The EPA has reviewers convened as part of the IRIS advisories can limit the beneficial provided detailed documentation for the process.218 aspects of fish consumption, and that choices underlying calculation of the The IRIS makes this statement fish advisories are often unsuccessful in RfD.213 214 215 To correct a regarding a threshold for MeHg, ‘‘It is changing behavior.209 210 One misunderstanding by the commenter, also important to note that no evidence commenter noted the important the data underlying the Faroe Islands of a threshold arose for methylmercury- protective role of dietary selenium study have been previously published related neurotoxicity within the range of against MeHg toxicity because the in the peer reviewed literature. exposures in the Faroe Islands study. binding affinity of Hg to Se is much The EPA disagrees that it did not This lack [of a threshold] is indicated by higher than binding to sulfur. incorporate the latest Hg data to support the fact that, of the K power models, K Response: The EPA agrees with the appropriate and necessary finding. It = 1 provided a better fit for the endpoint commenters that state the MeHg RfD is is the policy of EPA to use the most models than did higher values of K.’’ 219 the appropriate health value for current peer reviewed, publicly The EPA disagrees that it is using the determining elevated risks from MeHg available data and methodologies in its MeHg RfD as an absolute bright line for exposure and disagrees with risk assessments. However, the EPA health effects in the risk assessment. As commenters that state otherwise. At this noted in the preamble to the proposed stated in the preamble to this proposed time, the EPA is neither reviewing nor rule that ‘‘data published since 2001 are rule, the RfD is an estimate of a daily revising its 2001 RfD for MeHg. The generally consistent with those of the exposure to the human population that 2001 RfD for MeHg is EPA’s current earlier studies that were the basis of the is likely to be without an appreciable peer-reviewed RfD, which is the value RfD, demonstrating persistent effects in risk of deleterious effects during a EPA uses in all its risk assessments. The the Faroe Island cohort, and in some lifetime. The EPA also stated that no EPA’s RfD is based on multiple cases associations of effects with lower RfD defines an exposure level benchmark doses, and RfDs were MeHg exposure concentrations than in corresponding to zero risk. Because calculated on various endpoints using the Faroe Islands. These new studies mercury is a cumulative neurotoxin, it the three extant large studies of provide additional confidence that is important to distinguish health effects childhood effects of in utero exposure: exposures above the RfD are from public health hazard. Within the Faroe Islands, New Zealand, and an contributing to risk of adverse effects, context of the appropriate and necessary integrative measure including data from and that reductions in exposures above finding, we interpret a public health Seychelles. The EPA did not choose to the RfD can lead to incremental hazard as risk, rather than certain base the MeHg RfD solely on results reductions in risk.’’ However, the EPA occurrence of health effects. from the Seychelles Islands, as both the has not completed a comprehensive The EPA disagrees that exposure NAS 211 and an independent scientific review of the new literature, and as levels in the U.S. are lower than those review panel convened as part of the such, it would be premature to draw in the Faroe Islands study. Exposure to conclusions about the overall MeHg in the U.S. has been reported at implications for the RfD. 203 Roman HA, Walsh TL, Coull BA, Dewailly E´ , the same levels as those published in Guallar E, Hattis D, et al., 2011. Evaluation of the The EPA agrees that EPA’s RfD is not the Faroe Islands.220 One study notes Cardiovascular Effects of Methylmercury the same as the levels used by other that in the NHANES data (1999 to 2004), Exposures: Current Evidence Supports federal agencies. In their advice to the the highest five percent of women’s Development of a Dose–Response Function for EPA on the appropriate bases for a Regulatory Benefits Analysis. Environ Health blood Hg exceeded 8.2 microgram per Perspect 119:607–614. MeHg RfD, NAS specifically liter (mg/L) in the Northeast U.S. and 7.2 204 Guallar E, Sanz-Gallardo MI, van’t Veer P, et recommended that EPA use neither the mg/L in coastal areas.221 Higher levels al., 2002. ‘‘Mercury, fish oils, and the risk of study nor the uncertainty factor have been reported among subjects myocardial infarction.’’ N Engl J Med.;347:1747. employed by the Agency for Toxic known to consume fish. For example, 205 Virtanen JK, Voutilainen S, Rissanen TH, et Substances Disease Registry (ATSDR) in al., 2005. ‘‘Mercury, fish oils, and risk of acute one study reported mean blood Hg for coronary events and cardiovascular disease, the calculation of the minimal risk adult women to be 15 mg/L; range for coronary heart disease, and all-cause mortality in level.216 men in eastern Finland.’’ Arterioscler Thromb Vasc 217 Id. Biol. 2005;25:228. 212 U.S. EPA. 2001b. Responses to Comments of 218 U.S. EPA, 2001b. 206 Yoshizawa, Rimm, Morris, Spate, Hsieh, the Peer Review Panel and Public Comments on 219 U.S. EPA–IRIS, 2001. Spiegelman, Stampfer, Willett. ‘‘Mercury and the Methylmercury. Available on the Internet at http:// 220 Schober Susan E, Sinks Thomas H, Jones Risk of Coronary Heart Disease in Men,’’ N Engl J www.epa.gov/iris/supdocs/methpr.pdf. Robert L, Bolger P Michael, McDowell Margaret, Med 2002; 347:1755–1760. 213 U.S. EPA, 2001a. Water Quality Criterion for Osterloh John, Garrett E Spencer, Canady Richard 207 Hallgren CG, Hallmans G, Jansson JH, et al., the Protection of the Human Health: A, Dillon Charles F, Sun Yu, Joseph Catherine B, 2001. Markers of high fish intake are associated MethylmercuryEPA–823–T–01–001, available at Mahaffey Kathryn R. Blood mercury levels in U.S. with decreased risk of a first myocardial infarction. http://water.epa.gov/scitech/swguidance/standards/ children and women of childbearing age, 1999– Br J Nutr: 86:397. criteria/aqlife/pollutants/methylmercury/index.cfm. 2000. JAMA. 2003 Apr 2; 289(13): 1667–1674. 208 Mozaffarian, Dariush. 2011. ‘‘Mercury 214 U.S. EPA–IRIS, 2001. 221 Mahaffey, K.R., R.P. Clickner and R.A. Jeffries. Exposure and Risk of Cardiovascular Disease in 215 Rice D, Schoeny R, Mahaffey K. 2003. 2009. Adult Women’s Blood Mercury Two U.S. Cohorts,’’ N Engl J Med 364: 1116–1125. ‘‘Methods and Rationale for Derivation of a Concentrations Vary Regionally in the U.S.: 209 Hibbeln et al., 2007. Reference Dose for Methylmercury by the U.S. Association with Patterns of Fish Consumption 210 Mozaffarian, et al., 2011. EPA.’’ Risk Analysis 23(1)107–115. (NHANES 1999–2004). Environ. Health Perspect., 211 NAS, 2000. 216 NAS, 2000. 117: 47–53.

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men and women was 2 to 89.5 mg/L.222 above the RfD. While mean and 95th into tertiles by cord PCB Note that some publications have percentiles from recent NHANES data concentrations.239 These analyses reported Hg effects in U.S. populations are below the blood Hg concentration support a conclusion that there are at or below the current U.S. RfD.223 224 equivalent to the RfD, blood levels for measurable effects of MeHg exposure in Also, the EPA disagrees with the some portions of the population (high the Faroese children that are not commenter stating all ocean fish consumers of fish, for example) show attributable to PCB toxicity. We also throughout the world contain about the exposures above this level. One study note that there was no report of lead same amount of MeHg. Marine fish in estimated very high blood Hg levels at exposure in the Faroe Islands commerce differ widely in Hg the 99th percentile for females of child- population. concentration by species, and fish bearing age.228 Other published studies The EPA disagrees with the within the same species but caught at have shown that various population commenter’s assertion that the different locations have variable groups can have high blood Hg connection between MeHg in fish and amounts of Hg in their tissues.225 226 levels.229 230 231 232 233 For example, one observed health effects is not The EPA disagrees that there is a study found that 83 percent of the understood due to evidence from the statistically discernible downward trend NHANES Asian population exceeded cited Texas study.240 This is an in the NHANES data on blood Hg. The the RfD-equivalent blood mercury exposure study rather than a study on EPA is unaware that a formal statistical level.234 measures of neurobehavioral or any analysis for temporal trends has been The EPA disagrees with the other health endpoint. TCEQ noted that completed for NHANES data on blood commenter regarding confounding by none of the Caddo Lake study Hg levels for the period 1999 to 2008. PCBs and lead. Exposure to MeHg in the participants had blood Hg levels above Mahaffeyet al., evaluating NHANES Faroe Islands was largely from the benchmark dose level (BMDL) of 5.8 data collected 1999 to 2004 for women consumption of pilot whale meat; mg/L (one of the several used by EPA in at child-bearing age, could ‘‘not support exposure to PCBs was found in the the calculation of the MeHg RfD). The the conclusion that there was a general portion of the population who also BMDL is not a ‘‘no effect’’ level. Rather downward trend in blood Hg consume whale blubber. Numerous it is an effect level for a percentage of concentrations over the 6-year study analyses have shown neurobehavioral the population. The EPA has noted in period.’’ 227 However, the same effects of PCBs; however, the effects of correspondence with TCEQ that, as an publication noted that ‘‘there was a MeHg and PCB in the Faroe Islands exposure study, the Caddo Lake study decline in the upper percentiles study are separable.235 The EPA also may be representative of the reflecting the most highly exposed documented the independence of PCB surrounding population; however, the women’’ having blood Hg concentration and MeHg effects in the Faroe Islands sample size is very small. It is not greater than established levels of population.236 The National Institute of appropriate to extrapolate from Caddo concern. Visual observations of the data Environmental Health Sciences (NIEHS) Lake to larger regional or national show a slight decrease in Hg blood level concluded that both PCB and Hg had populations. concentrations from 1999–2008 at the adverse effects.237 The NAS concluded The EPA is aware of the possibility of geometric mean, but this decrease may that there was no empirical evidence or both interactions among environmental not be statistically significant. The EPA theoretical mechanism to support the contaminants and cumulative effects of remains concerned that substantial opinion that in utero Faroese exposure pollutants that produce the same numbers of women of childbearing age to PCBs exacerbated the reported MeHg adverse endpoint. The EPA guidance in the U.S. may have blood Hg levels effect.238 A second set of analyses found exists for dealing with such that are equivalent to exposures at or that the effect of prenatal PCB exposure scenarios.241 242 243 244 The Agency’s was reduced when the data were sorted concern with the likelihood of human 222 Hightower Jane M, Moore Dan. Mercury levels exposure to multiple contaminants is in high-end consumers of fish. Environ Health 228 Tran, N.L., L. Barraj, et al., 2004. ‘‘Combining Perspect. 2003 Apr; 111(4): 604–608. food frequency and survey data to quantify long- 239 Budtz-J

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reflected in the multi-chemical scope of other studies,249 250 a decrease of 1–2 The EPA disagrees that the Agency the rulemaking. However, the EPA points at the mean results in a much has overstated or failed to review the focused the technical analyses larger decrease in those with IQs that scientific literature on cardiovascular supporting the proposed regulation on are much lower or higher than the effects from MeHg exposure. As effects of individual pollutants rather mean. summarized in the preamble to the than cumulative effects. Although EPA disagrees that the IQ proposal, the EPA stated that the NAS The EPA disagrees with commenters results are too uncertain to rely upon, study concluded that ‘‘Although the suggesting that the RfD-based HQ is the EPA acknowledges that IQ is not the data base is not as extensive for inappropriate. The SAB ‘‘agreed that most sensitive neurodevelopmental cardiovascular effects as it is for other EPA’s calculation of a hazard quotient endpoint affected by MeHg exposure, as end points (i.e., neurologic effects) the for each watershed included in the also noted by the SAB. The SAB cardiovascular system appears to be a assessment is appropriate as the primary recommended that the IQ analyses be target for MeHg toxicity in humans and means of expressing risk,’’ and that retained but be de-emphasized in the animals.’’ 254 The EPA also stated that ‘‘because the RfD from which the HQ is documentation underlying the final additional cardiovascular studies have calculated is an integrative metric of regulation. The SAB concluded, ‘‘The been published since 2000. The EPA did neurodevelopmental effects of Panel does not consider it appropriate to not develop a quantitative dose methylmercury, it constitutes a use IQ loss in the risk assessment and 245 response assessment for cardiovascular reasonable basis for assessing risk.’’ recommended that this aspect of the effects associated with MeHg exposures, The SAB also recommended that EPA analysis be de-emphasized, moving it to as there is no consensus among revise the Hg Risk TSD to include an appendix where IQ loss is discussed scientists on the dose-response additional qualitative discussion about along with other possible endpoints not functions for these effects, and there is uncertainty in the revised Hg Risk TSD. included in the primary assessment. inconsistency among available studies Specifically, the SAB recommended that While the Panel agreed that the as to the association between MeHg EPA revise the Hg Risk TSD ‘‘to better concentration-response function for IQ exposure and various cardiovascular explain the methods and choices made loss used in the risk assessment is in the analysis, and analytical results, appropriate, and no better alternatives system effects. In the future, the EPA and where the uncertainties lie.’’ The are available, IQ loss is not a sensitive may update the MeHg RfD and will SAB noted several uncertainties related response to methylmercury and its use review all of the relevant scientific to the RfD. The EPA agrees with this likely underestimates the impact of literature available at that time, recommendation and included a more reducing methylmercury in water including data on all relevant complete discussion of these bodies.’’ 251 The EPA is following the endpoints, and weight of evidence for uncertainties in the revised Hg Risk SAB’s recommendation by likelihood that MeHg produces specific TSD. deemphasizing the IQ analysis and effects in humans. The EPA disagrees that the IQ metric placing that analysis in an appendix to The EPA acknowledges the research threshold is questionable. The SAB the revised Hg Risk TSD. regarding the effectiveness of fish concluded that it was reasonable to The SAB, however, supported the use advisories. However, the proposed consider a loss of >1 or >2 IQ points a of the IQ dose-response function regulation does not address the subject public health concern. The SAB stated, calculated by EPA in the Hg Risk TSD. of fish advisories, consumer advice on ‘‘The Panel agreed that if IQ loss is The SAB noted, ‘‘The function used fish or efficacy of such advice. The EPA retained in the risk assessment despite came from a paper by Axelrad and rejects the commenter’s speculation these reservations, a loss of one or two Bellinger (2007) that seeks to define a regarding whether the estimated IQ points would be an appropriate relationship between methylmercury impacts for the regulation are real. 246 benchmark.’’ The SAB further exposure and IQ. A whitepaper by Adverse effects of in utero Hg exposure comments in their report: ‘‘The Bellinger (Bellinger, 2005) 252 describes have been reported in populations in consensus is that if IQ were to be used, the sequence of steps in relating the U.S.255 256 In another study on then a loss of 1 or 2 points as a methylmercury exposure to maternal neurobehavioral effects of prenatal population average is a credible hair mercury and then that to IQ. The exposure to MeHg through maternal decrement to use for this risk Mercury Risk TSD furthers notes that IQ consumption of seafood, adverse effects assessment. This metric seems to be has shown utility in describing the are observed for MeHg even without derived from the lead literature and was health effects of other neurotoxicants. controlling for fish consumption.257 peer reviewed by the Clean Air These are appropriate bases for That study suggests that at normal Scientific Advisory Committee (U.S. examining a potential impact of Japanese dietary intake of MeHg and EPA CASAC 2007).247 Although its reducing methylmercury on IQ, but the fish nutrients, the overall effect is applicability to methylmercury is SAB does not consider these compelling adverse. While Japanese fish questionable, the size of the decrement reasons for using IQ as a primary driver consumption and Hg exposure are both is justified based on the extensive of the risk assessment.’’ 253 analyses available from the literature somewhat higher than the mean U.S. 248 exposure, these levels are still within reviewed by CASAC.’’ As noted in 249 Axelrad, D. A.; Bellinger, D. C.; Ryan, L. M.; Woodruff, T. J. 2007. ‘‘Dose-response relationship of the distribution of U.S. consumers. 245 U.S. EPA–SAB, 2011. prenatal mercury exposure and IQ: An integrative 246 U.S. EPA–SAB, 2011. analysis of epidemiologic data.’’ Environmental 254 76 FR 25001. Health Perspectives, 115, 609–615. 255 247 U.S. Environmental Protection Agency— Oken et al., 2008. 250 Science Advisory Board (U.S. EPA–SAB). 2007. Bellinger DC. 2005. Neurobehavioral 256 Lederman et al., 2008. Clean Air Scientific Advisory Committee’s (CASAC) Assessments Conducted in the New Zealand, Faroe 257 Suzuki, K., Nakai, K., Sugawara, T., Review of the 1st Draft Lead Staff Paper and Draft Islands, and Seychelles Islands Studies of Nakamura, T., Ohba, T., Shimada, M., Hosokawa, Lead Exposure and Risk Assessments. EPA– Methylmercury Neurotoxicity in Children. Report to T., Okamura, K., Sakai, T., Kurokawa, N., Murata, CASAC–07–003. March. Available on the internet at the U.S. Environmental Protection Agency. EPA– K., Satoh, C., and Satoh, H. 2007. ‘‘Neurobehavioral http://yosemite.epa.gov/sab/sabproduct.nsf/ HQ–OAR–2002–0056–6045. effects of prenatal exposure to methylmercury and 989B57DCD436111B852572AC0079DA8A/$File/ 251 U.S. EPA–SAB, 2011. PCBs, and seafood intake: neonatal behavioral casac-07–003.pdf. 252 Bellinger, 2005. assessment scale results of Tohoku study of child 248 U.S. EPA–SAB, 2011. 253 U.S. EPA–SAB, 2011. development.’’ Environ Res 110, 699–704.

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Moreover, many studies show that quantitative impact to support a health risks posed by utility hazardous beneficial effects of fish on both recommendation of a re-analysis.’’ 269 air pollutant emissions. One commenter cardiovascular and neurodevelopmental stated that EPA did not consider 6. General Comments on Hg Risk scientific information showing that health are decreased by concomitant Assessment exposure to MeHg. Several studies there is no straightforward connection describe one or more aspects of Comment: Several commenters between Hg emissions from U.S. EGUs exposure to fish nutrients and generally supported the Hg risk to the Hg level in fish, which is MeHg.258 259 260 261 262 263 264 Recent assessment, but several other dependent upon many environmental studies 265 266 267 and analyses indicate commenters generally disagreed with factors, such as sunlight and organic the potential for nutrients in fish the Hg risk assessment. One supporter matter, pH, water temperature, sulfate, (particularly marine fish) to mask some stated that EPA reasonably determined bacteria, and zooplankton present in the of the observed adverse effects of MeHg. that Hg emissions pose a public health ecosystem. One commenter stated that Because EPA did not adjust for potential hazard, correctly requested peer review there is not any demonstrable evidence confounding by nutrients in marine fish of Hg risk analysis and correctly that anyone in the U.S. has suffered and mammals, the benchmark doses concluded EGU-attributable MeHg poses adverse health problems as a result of a hazard to public health at watersheds used in the RfD derivation may be Hg emissions from coal-fired EGUs. One when considering all sources of Hg underestimated. commenter stated that EPA’s findings deposition and U.S. EGUs alone. Two are similar to the 2000 findings where The EPA recognizes the potential for commenters noted that the contribution EPA found a plausible link between confounding of the effects of Hg on the of U.S. EGUs to total Hg deposition can anthropogenic emissions of Hg from developing nervous system by a range of significantly contribute to hundreds of sources in the U.S. and MeHg in fish, nutrients and discusses this uncertainty watersheds, and U.S. EGU deposition and ‘‘plausible’’ is a euphemism for in the revised Hg Risk TSD. Regarding alone may endanger sensitive unproven. selenium, the SAB commented that populations near many of these Several commenters had ‘‘one SAB member suggests the use of watersheds. recommendations for the Hg risk blood markers of selenium-dependent Several commenters claimed that analysis. One commenter stated that enzyme function, noting that overly conservative assumptions in the more data from Florida should have methylmercury irreversibly inhibits risk analysis render the results flawed been included because Florida is known selenium-dependent enzymes that are and unreliable, including using CMAQ to have a rich data set on fish Hg required to support vital-but-vulnerable to model deposition, Mercury Maps, fish consumption rate and fish MeHg concentrations. One commenter stated metabolic pathways in the brain and that EPA should characterize general endocrine system. Impaired concentrations, overly stringent RFD, national-scale model, using poverty as a recreational angler fishers instead of selenoenzyme activities would be subsistence fishers. One commenter observed in the blood before they would surrogate for subsistence fishing, assuming a subsistence fisher resides in claims that EPA made math errors in the be observed in brain, but the effect is Hg Risk TSD regarding the deposition in also expected to be transitory. The use most watersheds with fish tissue data, fishers only eat larger fish with high Hg watersheds at specific percentiles. One of these measures is a minority view commenter questioned EPA’s policy 268 concentrations, cooking loss adjustment, among the SAB members.’’ The SAB metrics used to characterize Hg risk. did not express a consensus unrealistically high fish ingestion rates (a large fish meal every day), focused on Several commenters stated that the Hg recommendation on adjustments to the TSD is unclear and lacks detail, as noted risk estimates for exposure to selenium the extremes of the distributions, cast many assumptions as an underestimate by the SAB. One commenter stated that or other nutrients, noting that ‘‘there is the SAB is critical of EPA’s efforts, not enough known about their of the effect despite evidence to the contrary, and created inappropriate stating that the SAB found it difficult to metrics for risk that show no evaluate the risk assessment based 258 Grandjean P, Bjereve K, Wihe P, and solely upon Hg Risk TSD and Sterewald u. 2001a. ‘‘UBirthweight in a fishing improvement despite significant Hg community: significance of essential fatty acids and emissions reductions in the U.S. recommended that EPA transparently marine food contaminants.’’ In. J. Epidemiol. Several commenters cite Tetra Tech’s explain the methods and uncertainties. 30:1272–1278. analysis that assessed Hg risk using One commenter stated that because of 259 Budtz-Jorgensen, E.; Grandjean, P.; Weihe, P. different consumption rates, cooking insufficient review time and the lack of 2007. ‘‘Separation of risks and benefits of 16 detail in the Hg Risk TSD, they could seafood intake.’’ Environmental Health factor, mean fish tissue concentrations, Perspectives. Vol. 115, 323–327. and EGU-attributable Hg deposition not assess key questions, such as the 260 Choi et al., 2008a. only, which showed considerably fewer nation-wide representativeness of the 261 Choi et al., 2008b. watersheds that exceed an HQ of 1 at fish tissue data. 262 Oken et al., 2008. 2016 deposition levels. One commenter stated the subset of 263 Strain, J.J. et al., 2008. Associations of Several commenters claim that this watersheds considered in the analysis maternal long chain polyunsaturated fatty acids, methyl mercury, and infant development in the regulation would not significantly (i.e., with fish tissue data) have clearly Seychelles Child Development Nutrition Study.’’ reduce Hg exposure via fish higher U.S. EGU-attributable deposition Neurotoxicology. 29(5): 776–782. consumption because EGU-attributable than the distribution of all watersheds. 264 Suzuki, et al., 2007. deposition is a small fraction of total One commenter stated EPA’s 265 Oken et al., 2008. deposition. One commenter stated that reporting of IQ point loss is erroneous 266 Choi AL, Cordier S, Weihe P, Grandjean P. and not relevant to informing policy, 2008a. ‘‘Negative confounding in the evaluation of EPA’s data shows Hg emissions from toxicity: the case of methylmercury in fish and U.S. EGUs have little influence on fish and the U.S. EGU contribution to risk is seafood.’’ Crit Rev Toxicol. 2008;38(10):877–93. Hg concentrations despite a reduction of marginal as evidenced by the null 267 Choi AL, Budtz-J

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and 2016, but claims that this decrease review process and determined that revised Hg Risk TSD suggest that higher does not appear to affect the risk results. ‘‘the SAB supports the overall design of percentile subsistence fishers eat more Response: The purpose of the Hg risk and approach to the risk assessment and than twice the level of fish assumed by assessment is not to assess the finds that it should provide an objective, Tetra Tech. Tetra Tech’s analysis also magnitude of risk reduction under the reasonable, and credible determination used the median fish tissue levels, but proposed rule, but rather to estimate the of the potential for a public health it is reasonable to assume that magnitude of absolute risk attributable hazard from mercury emitted from U.S. subsistence fishers would target to U.S. EGUs currently and following EGUs.’’ 272 The primary advice of the somewhat larger fish to maximize the implementation of other applicable SAB panel was that EPA should ‘‘revise volume of edible meat per unit time CAA requirements. That said, any the Technical Support Document to spent fishing. Tetra Tech’s analysis also potential risk reductions following better explain the methods and choices assumed that cooking fish did not implementation of the MACT rule itself made in the analysis, and analytical concentrate Hg, but a number of studies would likely reflect a number of factors results, and where the uncertainties discussed in the revised Hg Risk TSD besides the national average U.S. EGU lie.’’ 273 The EPA has revised the Hg explicitly provide adjustment factors deposition value cited by the Risk TSD as part of the final rulemaking involving a higher unit concentration commenter. These additional factors to address the SAB’s recommendations following preparation. Taken together, include: (a) Spatial gradients in the and has made that revised Hg Risk TSD Tetra Tech’s analysis does not address magnitude of absolute U.S. EGU- available in the rule docket. the stated goal of the risk assessment to attributable Hg deposition, (b) spatial The SAB concurred with EPA’s assess the nature and magnitude of risk gradients in the magnitude of reductions analytical assumptions and overall for those individuals likely to in Hg deposition linked to the rule, (c) study design for the Hg Risk TSD, experience the greatest risk associated availability of measured fish tissue Hg including the RfD-based HQ approach, with exposure to U.S. EGU-attributable levels in the vicinity of U.S. EGUs fish tissue data, 75th percentile size Hg. experiencing larger Hg emission fish, Mercury Maps assumption, and The EPA disagrees with the reductions to support risk modeling, consumption rates. Based on the SAB commenter’s assertion that this rule will and (d) the potential for subsistence peer review, the EPA strongly disagrees not affect risks associated with Hg fishing activity at watersheds in the with commenter statements that the exposure. Hg from U.S. EGUs vicinity of U.S. EGUs experiencing results reported in the Hg Risk TSD are contributes to the levels of MeHg in fish larger reductions in Hg emissions (also unreliable, overly conservative, extreme, across the country and consumption of required to support risk modeling). It is inconsistent with EPA risk guidelines, contaminated fish can lead to increased also important to point out that while or severely overstate risk based on the risk of adverse health effects. The EPA the national average U.S. EGU- stated objectives of the analysis. The has shown in the RIA (Chapter 5) that attributable Hg deposition (for the 2016 EPA has specifically addressed each of this rule will reduce Hg levels in fish. scenario—see revised Hg Risk TSD) is these assumptions in the previous The EPA acknowledges that U.S. two percent, values range up to 11 sections of the preamble, and thus, does EGUs contribute only a small fraction of percent for the 99th percentile not repeat those responses here. Based total Hg deposition in the U.S. However, watershed. This illustrates the on the review by the SAB, the EPA has U.S. EGUs remain the largest emitter of substantial spatial variation in U.S. accurately described the health risks Hg in the U.S., and the revised Hg Risk EGU-attributable Hg deposition, which posed by utility hazardous air pollutant TSD shows that U.S. EGU-attributable translates into spatial variation in the emissions and disagrees with the Hg deposition results in up to 29 magnitude of U.S. EGU-attributable commenter’s statement that EPA has not percent of modeled watersheds with subsistence fisher risk. provided any demonstrable evidence to populations potentially at-risk. Our The SAB conducted a comprehensive show that adverse health risks exist. The analyses show that of the 29 percent of peer review of all of EPA’s assumptions EPA has applied peer reviewed watersheds with population at-risk, in in the Hg Risk TSD, and concluded that modeling to estimate the deposition of 10 percent of those watersheds U.S. ‘‘the SAB supports the overall design of Hg attributable to U.S. EGUs. The EPA EGU deposition alone leads to potential and approach to the risk assessment and asserts that these metrics demonstrate a exposures that exceed the MeHg RfD, finds that it should provide an objective, clear hazard to public health from Hg and in 24 percent of those watersheds, reasonable, and credible determination emissions from U.S. EGUs. total potential exposures to MeHg of the potential for a public health The EPA thoroughly evaluated the exceed the RfD and U.S. EGUs hazard from Hg emitted from U.S. Tetra Tech analysis. The EPA does not contribute at least 5 percent to Hg EGUs.’’ 270 Furthermore, the SAB agree that the analysis by Tetra Tech deposition. Mercury risk is increasing concluded, ‘‘The SAB regards the design uses assumptions that are ‘‘more for exposures above the RfD, and as a of the risk assessment as suitable for its reasonable’’, and the SAB agreed that all result, any reductions in Hg exposures intended purpose, to inform decision- of EPA’s assumptions in the Hg Risk in locations where total exposures making regarding an ‘‘appropriate and TSD are reasonable and appropriate. exceed the RfD can result in reduced necessary finding’’ for regulation of The EPA asserts that Tetra Tech’s risks. While these reductions in risk hazardous air pollutants from coal and analysis does not fully cover subsistence may be small for most populations and oil-fired EGUs, provided that our fishers likely to experience elevated locations, in some watersheds and for recommendations are fully considered U.S. EGU-related Hg exposure. some populations, reductions in risk in the revision of the assessment.’’ 271 Specifically, the risk estimate cited in may be greater. Although the SAB did indicate the comment reflects application of a The SAB also directly addressed the difficulty in evaluating the risk number of behavioral assumptions that question of the nation-wide assessment based solely on the Hg Risk provide significantly less coverage for representativeness of the fish tissue TSD, the panel obtained additional higher risk subsistence fishers. Fish MeHg data in the national Hg risk information from EPA through the peer consumption surveys cited in the assessment. The SAB concluded, ‘‘Although the SAB considers the 270 U.S. EPA–SAB, 2011. 272 Id. number of watersheds included in the 271 Id. 273 Id. assessment adequate, some watersheds

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in areas with relatively high mercury agrees that the subset of watersheds in made detailed technical comments, deposition from U.S. EGUs were under- the risk analysis have somewhat higher including many of the same comments sampled due to lack of fish tissue U.S. EGU deposition than the as the SAB. Furthermore, the EPA methy[l]mercury data. The SAB distribution of all watersheds, but EPA provided notice of the peer review in encourages the Agency to contact states disagrees that oversampling of high the preamble to the proposed rule and with these watersheds to determine if deposition watersheds is inappropriate. a number of Federal Register notices additional fish tissue methylmercury The EPA does not agree that there is advised the public of the peer review data are available to improve coverage no improvement in fish Hg process and all the meetings were open of the assessment.’’ 274 In response to concentrations between 2005 and 2016, to the public for comment and the SAB’s recommendations, the EPA or that there will be no further participation and the minutes of those obtained additional fish tissue sample improvement from decreasing Hg meetings were posted on the SAB Web data from several states, particularly emissions from U.S. EGUs from the site. The minutes for the June 2011 Pennsylvania, Wisconsin, Minnesota, baseline in 2016. Although total risk meeting, during which EPA provided New Jersey, and Michigan. This from all Hg exposures will remain clarifying information, were available additional data increased the total elevated in much of the U.S., much of well within the public comment period number of watersheds assessed in the that risk is associated with global, non- for the proposed rule. For these reasons, analysis by 33 percent nationally. In U.S. Hg emissions. U.S. EGUs remain we maintain that the public was Florida, the EPA assessed the Hg-related the largest source of Hg emissions in the provided an adequate opportunity to health risk for 40 watersheds. Because U.S., and reductions in those emissions comment on the Hg risk assessment. EPA did not find any additional fish will result in reduced Hg deposition in tissue data for watersheds in Florida many highly impacted watersheds. As e. Non-Hg HAP Case Studies that could be incorporated into the shown in the revised Hg Risk TSD, 1. Emissions for Non-Hg Case Studies analysis, the total number of watersheds average U.S. EGU-attributable fish tissue in Florida assessed in the revised Hg Hg concentrations is estimated to Comment: The commenters raised Risk TSD remains the same as the Hg decrease by 44 percent between 2005 concerns about a wide variety of aspects Risk TSD at proposal. and 2016. Although we did not remodel of EPA’s approach for emissions used The EPA disagrees with the risk for the 2005 scenario in the revised for the non-Hg case studies, including commenter that there were errors in the Hg Risk TSD, we estimated at proposal the use of an arithmetic mean for Hg Risk TSD. Instead, the commenter that the total percent of modeled computing emission factors for has misinterpreted how EPA calculated watersheds with populations potentially representing emissions of untested the percentiles. The percentile (and at-risk from Hg emissions from U.S. units, the suggestion of statistical mean) values presented in Table ES–1 EGUs exceeding either risk metric (i.e., outliers in the Cr test data, the claim for total and U.S. EGU-attributable Hg U.S. EGUs alone or total potential that metals content of the fuel is an deposition are not matched by exposures to MeHg exceed the RfD and indicator of flawed test data, the watershed. In other words, the EPA U.S. EGUs contribute at least 5 percent) statistical approaches used by EPA to queried for the percentiles (and mean) would decline from 62 percent in 2005 create emission factors, the absence in provided for total Hg deposition and to 28 percent in 2016. This projected EPA’s approach of an equation that presented those percentiles and then decline is primarily due to a commenters claim better represents separately estimated the percentiles for combination of additional pollution emissions values, that EPA’s approach U.S. EGU-attributable Hg. Therefore, the control technologies installed to comply to estimate Cr(VI) is flawed, and the lack total and U.S. EGU-attributable values with federal regulations, such as of coal rank as a delineating factor for for the 99th percentile do not CSAPR, and changing fuels, such as the emission factor calculation. The necessarily occur at the same watershed. shift to natural gas. commenters also suggested that EPA The EPA has provided additional The EPA disagrees that IQ loss is should revise stack parameters used for erroneous or irrelevant to informing clarification in the revised Hg Risk TSD. the case studies based on better policy, but EPA has moved that analysis The EPA agrees with the commenter available data. that MeHg levels in fish depend on a to an appendix in the revised Hg Risk complicated set of environmental TSD, per the SAB’s recommendation. Response: In response to the factors, and EPA acknowledged this in The EPA disagrees that the IQ effects at comments on the emission factors, the the revised Hg Risk TSD. Furthermore, the 50th percentile watershed are useful EPA has undertaken additional analysis the EPA acknowledges that total Hg fish in determining that there is not a hazard to address all commenter concerns. The tissue levels are not correlated with to public health because EPA’s stated EPA disagrees with commenter’s levels of total Hg deposition when goal of the risk assessment was to focus criticisms of emission factors based on looking across watersheds because this on populations likely to experience arithmetic means, and EPA relationship is highly dependent on the relatively higher exposures to U.S. EGU- demonstrates that the use of an methylation potential at the specific attributable Hg. arithmetic mean provides the most waterbody, which is affected by pH, We also disagree with those representative result. The EPA analysis sulfate deposition, turbidity, etc. commenters that point to the SAB’s has found that the geometric mean However, several recent studies 275 276 277 statements concerning the clarity of the approach recommended by the show, and the SAB agrees, that it is Hg Risk TSD to suggest that the public commenter always under predicts actual appropriate for EPA to assume that did not have an ample opportunity to emissions by an average of more than changes in Hg deposition are linearly comment on the Hg risk assessment. seventy percent. The EPA agrees with associated with changes in fish tissue Although it is correct that the SAB said commenters’ recommendations to use concentration. In addition, the EPA the Hg Risk TSD was difficult to statistical outlier tests, but has applied evaluate until EPA staff explained it at tests different from those suggested by 274 U.S. EPA–SAB, 2011. the public meeting in June 2011, we the commenters. As further explained in 275 Orihel et al., 2007. note that the commenters that assert that the response to comments document in 276 Orihel et al., 2008. this issue amounts to a violation of CAA the docket, this approach did not 277 Harris et al., 2007. section 307(d) notice requirements eliminate the Cr test data from the Cr

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emission factors used for some of the The EPA also disagrees that coal rank One commenter stated that EPA’s case study emissions. must be a factor in computing Cr discussion in the preamble to the The EPA disagrees with commenters’ emission factors for use in the case proposed rule misleads the reader into assertions that the metal content of the studies. The EPA’s analysis has believing that non-Hg HAP emissions coal is a basis for invalidating the test demonstrated that coal rank appears to from EGUs are associated with serious results of high Cr emissions. The play no role in non-Hg metals human health effects. According to the identification of sources whose emissions. The EPA’s newly revised commenter, the EPA’s discussion of the measured emissions do not match the emissions factor development effects associated with excessive commenters’ preconceived idea of procedures can isolate and compare exposure to an individual HAP would emissions behavior is not surprising. subgroups based on control device type lead the reader to believe that those There are many possible explanations or coal rank; the ICR data were effects inevitably occur from EGU for these differences. For example, the subjected to these tests and no statistical emissions because EGU emissions have inconsistency between the test data and significance was found between coal trace amounts of non-Hg HAP. the coal analysis could be due to any rank groups. One commenter stated that with the number of reasons including Finally, the EPA agrees with one assumptions in the Utility Study, both unrepresentative coal sampling, control commenter’s recommendations on in terms of conservative scientific device problems, degradation of the revised stack parameters for the case estimates and overestimated amounts of refractory, or sampling contamination. studies and has included these revisions oil burned by these units, the EPA The idea that test data should be in the case study modeling for the final concluded that the risks from oil-fired discarded because it does not match rule. units would result in only one new initial expectations is unfounded. cancer case every 5 years. The 2. General Comments on Non-Hg Risk The EPA disagrees with the commenter does not believe that this Case Study commenter recommendations for using level of risk warrants regulation under an equation from AP–42, developed in Comment: One commenter stated that CAA section 112(n)(1)(A). part by the commenters. Based on EPA’s case study assessment reaffirms Several commenters stated that even analyses of metal emissions measured at the need to regulate HAP emitted by if the additional studies EPA performed the site compared to statistically both coal and oil-fired EGUs. The were accurate, they hardly demonstrate predicted estimates, the EPA concluded commenter noted that over 40 percent of that it is necessary and appropriate to that measured emissions test data better the case studies conducted by EPA to regulate coal-fired EGU HAP under CAA predict actual emissions, and emission quantify health hazards associated with section 112 because three sites factors based on the arithmetic mean are the inhalation of non-Hg HAP indicated nationwide show risks greater than one a reasonable method to estimate a cancer risk greater than or equal to the in a million, with the highest at eight in emissions when test data are not one in a million threshold level required a million. available. The EPA analysis of the ICR to delist a source category under CAA data has found that the emissions One commenter stated that the section 112. equation recommended by the highest cancer risk estimated for coal- commenter is not a good predictor of One commenter stated that EPA’s case fired EGUs is still within the acceptable actual EGU emissions. The EPA also study assessment might be flawed by range used by EPA in other programs disagrees with commenters’ concerns the use of ‘‘beta’’ tests versions of the and is also far less than the background about the assumption that 12 percent of AERMOD meteorological preprocessors exposure risks the average person the Cr will be Cr(VI) for every coal-fired (AERMINUTE and AERMET). The experiences. The background risk of unit, which was specifically supported commenter obtained from EPA the developing cancer in a lifetime is by the peer review on the approach for meteorological data used for EPA’s approximately one in three (0.33). estimating cancer risks associated with assessment of the Conesville facility and According to EPA’s own data, the Cr and Ni emissions. The EPA disagrees processed these data with EPA’s current predicted added cancer risk of exposure with the commenter’s assertion that any regulatory versions of these to HAP from U.S. EGUs would change impact of scrubbers will impact the case preprocessors, which differ from the the background risk from 0.33 to study analyses. In EPA’s revised case beta version. According to the 0.330001. This level of change is so study analysis, 6 facilities have risk commenter, a comparison of the hourly minimal that it could not be observed in greater than 1 in a million, and of these, wind speed and hourly wind direction any health effects study that might be four facilities have Cr as the risk driver data produced by the beta preprocessor conducted. (James River, Conesville, TVA Gallatin, and by current EPA preprocessors One commenter stated that EPA and Dominion—Chesapeake Bay). For revealed numerous and often substantial conducted a health risk assessment on these facilities, none of the units disparities. a limited number of facilities and found contributing the bulk of the Cr One commenter stated that EPA’s a ‘‘few’’ facilities that have estimated emissions have scrubbers according to finding that only three coal-fired maximum cancer risks in excess of one the data provided to EPA by those facilities and one oil-fired facility out of in a million. The commenter stated that, facilities, so scrubber impacts on Cr roughly 440 coal-fired facilities and 97 based on this limited health risk speciation is not relevant to EPA’s oil-fired facilities in the U.S. indicated assessment, the EPA apparently decided conclusions based on the non-Hg case risk greater than one-in-a-million that they were justified to regulate all studies. In any case, the EPA disagrees supports a finding that it is non-Hg HAP for all sources in this with the commenter’s conclusions about ‘‘appropriate’’ to regulate those four and category. the impacts of scrubbers on Cr not the other 537. Another commenter Several commenters stated that EPA’s speciation and provides evidence that stated that EPA found only a ‘‘few’’ assumption implies that a person stays impacts of scrubbers on Cr speciation facilities that have estimated maximum exactly at the center of a census tract for can have the opposite effect on Cr(VI) cancer risks in excess of one in a 70 years and that a unit will operate in fractions, concluding that EPA’s 12 million, and that this does not justify exactly the same manner for 70 years is percent assumption is somewhat regulating all non-Hg HAP for all unrealistic. The commenters suggest conservative. sources in this category. that Tier 3 risk assessment is warranted

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or a lifetime exposure adjustment is EGUs at other facilities). Because the EPA reasonably looked to the cancer needed. ICR data were collected for the purpose risk threshold established under CAA One commenter asserts that because of developing the MACT standards, the section 112(c)(9)(B)(1) for delisting a the alleged health benefits are derived ICR was targeted towards better source category as an indicator of the from total exposure, the EPA should performing sources for non-Hg metal level of cancer risk that was appropriate explain how its numerical emission HAP, acid gas HAP, and organic HAP, to regulate under CAA section 112. The limit units, which would not directly with a smaller set of random recipients. commenters comparison of the cancer restrict total exposure if heat inputs Therefore, facilities for which ICR data risk from EGUs as compared with the increase, redress this health concern. In were available may not represent the risk of contracting cancer from its preamble, the EPA simply notes that highest-emitting sources. The EPA’s unknown sources is not the standard its emission limit units are consistent assessment of the case study facilities Congress established for evaluating HAP with, and allow for simple comparison for the proposed rule concluded that emission risk and the commenter has to, other regulations. three coal-fired facilities and one oil- provided no support for its contention One commenter questioned whether fired facility had estimated lifetime that the Agency should evaluate risk in acid gas emissions limits for oil-fired cancer risks greater than one in a that manner. The EPA maintains that units are ‘‘appropriate’’ or ‘‘necessary’’ million. For the final rule, revisions the analysis was reasonable. because EPA’s new technical analyses were made to the 16 case studies based do not indicate a health concern from on comments received, and the results The EPA does not agree with the acid gas emissions from oil-fired units. indicate that 5 coal-fired facilities and 1 commenter’s implication that EPA must According to the commenter, the EPA oil-fired facility had estimated lifetime make a facility-specific finding for each identifies Ni as the main HAP of cancer risks greater than 1 in a million. HAP for each source and then only concern from oil-fired units, even The EPA maintains that its finding that regulate individual EGU facilities for the though cancer-related inhalation risks more than 30 percent of the case study individual HAP that identified as were well below the RfCs and EPA facilities had a cancer risk greater than causing an identified hazard to public states that significant uncertainty one in a million is sufficient to support health or the environment. That remains as to whether those emissions the appropriate finding. approach is not required under CAA present a health concern. The EPA disagrees with the section 112(n)(1) or anywhere under Response: The EPA agrees with the commenter’s assertion that the health CAA section 112, and it would be commenter that the non-Hg HAP risk effects associated with exposures to virtually impossible to undertake such assessment confirms the appropriate non-Hg HAP from U.S. EGUs are an effort. For these reasons, the EPA and necessary finding. mischaracterized in the preamble to the does not agree with the commenter and The EPA disagrees that EPA’s case proposed rule. The discussion of the maintains that the appropriate and study assessment is flawed by the use of health effects of non-Hg HAP provided necessary finding is reasonably beta versions of AERMINUTE and in the preamble includes general supported by the record and consistent AERMET. The EPA remodeled the case information on the potential health with the statute for all the reasons set study facilities using the current effects associated with a broad range of forth in the preamble to the proposed versions of AERMINUTE (version exposure concentrations (from low to rule and this final action. 11059), AERMET (version 11059), and high levels) of the various non-Hg HAP AERMOD (version 11103). Although The EPA disagrees that an exposure (some of which have been determined to adjustment is needed to account for there were differences in the number of be carcinogenic to humans) based on conditions changing over 70 years calm and missing winds in the current peer reviewed scientific information because it runs counter to the long- AERMINUTE/AERMET output extracted from priority sources such as standing approach that EPA has taken to compared to the beta version, the IRIS, Cal EPA and ATSDR health effects estimate the maximum individual risk, resulting risks differed by less than two assessments. percent, on average. For Conesville, The EPA disagrees with the or MIR. The MIR is defined by EPA’s 278 which had the largest difference in commenter’s characterization of the Benzene NESHAP regulation of 1989 calms between the beta and current Utility Study. The Utility Study and codified by CAA section 112(f) as versions of AERMINUTE/AERMET, the represented the highest-quality factual the lifetime risk for a person located at risks differed by three percent. For the record of information available at the the site of maximum exposure 24 hours final rule, the case study facilities have time regarding EGU emissions and risks. a day, 365 days a year for 70 years (e.g., been modeled with the current available Further, the EPA’s revised risk census block centroids). The MIR is the versions of AERMINUTE, AERMET, and assessments of 16 case studies, metric associated with the AERMOD. performed with more recent data and determination of whether or not a The EPA disagrees with the refined scientific methods, indicate that source category may be delisted from commenter that having only a few case there are six U.S. EGU facilities that regulatory consideration under CAA study facilities exceeding one in a pose estimated inhalation cancer risks section 112(c)(9). The MIR is the risk million risk invalidates the ‘‘appropriate greater than 1 in a million. The EPA metric used to characterize the finding’’. The 16 facilities EPA selected maintains that the findings of the case inhalation cancer risks associated with as case studies for assessment may not studies are one element that the case study facilities. The EPA used represent the highest-emitting or independently supports our the annual average ambient air highest-risk sources. Although case determination that it remains concentration of each HAP at each study facility selection criteria included appropriate and necessary to regulate census block centroid as a surrogate for high estimated cancer and non-cancer EGUs under CAA section 112. the lifetime inhalation exposure risks using the 2005 NEI data, high The EPA does not agree with the concentration of all the people who throughput, and minimal emission commenter who suggested that EPA reside in the census block. The EPA has control, another necessary criterion was should interpret the results of the non- used this approach to estimate MIR the availability of Information Hg HAP risk analysis in the context of values in all of its risk assessments to Collection Request (ICR) data for the background cancer risk. As explained in EGUs at those facilities (or for similar the preamble to the proposed rule, the 278 54 FR 38044.

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support risk-based rulemakings under assessment of the risks to human health compounds carcinogenic as a group. CAA section 112 to date. from Ni emissions from EGUs, and These reviewers, therefore, did not The EPA disagrees with the maintains that its assessment of the focus on the availability of Ni speciation commenter’s assertion that the potential inhalation risks from EGU profile data. The third reviewer numerical emission limits being emissions of Ni compounds is recommended that EPA review several promulgated in today’s final rule must scientifically valid, reasonable, and manuscripts on Ni speciation profiles be justified on their ability to redress the based on the best-available current showing that sulfidic Ni compounds health concerns that were identified as scientific understanding. To that end, in (which the reviewer considered as the the basis for regulating EGUs. The July 2011, the EPA completed an most potent carcinogens) are present at emission limits in today’s rule are external peer review (using three low levels in emissions from EGUs. technology-based, as prescribed under independent expert reviewers) of the Nickel and Ni compounds have been CAA section 112, and do not need to be methods used to evaluate the risks from classified as human carcinogens by justified based on their ability to protect Ni and Cr compounds emitted by national and international scientific public health. Regarding potential EGUs.279 There were two charge bodies including the IARC,283 the World health concerns, the EPA has up to 8 questions relating to Ni in that review. Health Organization,284 and the years after the promulgation of the First, do EPA’s judgments related to European Union’s Scientific Committee technology-based emission limits for speciated Ni emissions adequately take on Health and Environmental Risks.285 EGUs to determine whether the into account available speciation data, In their 12th Report of the Carcinogens, regulations protect public health with including recent industry spectrometry the NTP has classified Ni compounds as an ample margin of safety. If the studies? Second, based on the known to be human carcinogens based regulations do not, the CAA directs EPA speciation information available and on sufficient evidence of carcinogenicity to promulgate additional more stringent what is known about the health effects from studies in humans showing standards (within the prescribed 8 of Ni compounds, and taking into associations between exposure to Ni years) to achieve the appropriate level of account the existing URE values (i.e., compounds and cancer, and supporting public health protection. values derived by the Integrated Risk animal and mechanistic data. More Furthermore, the EPA reasonably Information System,280 California specifically, this classification is based concluded that it was appropriate and Department of Health Services,281 and on consistent findings of increased risk necessary to regulate oil-fired EGUs in the Texas Commission on of cancer in exposed workers, and 2000, and EPA confirmed that Environmental Quality 282), which of the supporting evidence from experimental conclusion was proper with the analysis following approaches to derive unit risk animals that shows that exposure to an set forth in the preamble to the estimates would result in a more assortment of Ni compounds by proposed rule. Certain commenters accurate and defensible characterization multiple routes causes malignant question the determination based on of risks from exposure to Ni tumors at various organ sites and in their views of how the Agency can and compounds? multiple species. The 12th Report of the should exercise its discretion. The EPA 1. To continue using the same Carcinogens states that the ‘‘combined disagrees with these commenters and approach as that developed for use in results of epidemiological studies, stands by the determination for the the 2000 NATA, which consists of using mechanistic studies, and carcinogenesis reasons set forth in the preamble to the the IRIS URE for nickel subsulfide and studies in rodents support the concept proposed rule. The EPA also stands by assuming that nickel subsulfide that Ni compounds generate Ni ions in the determination that the maximum constitutes 65 percent of the mass target cells at sites critical for cancer risks posed by emissions of oil- emissions of all Ni compounds. carcinogenesis, thus allowing fired EGUs are greater than one in a 2. To consider a more health- consideration and evaluation of these million, due primarily to emissions of protective approach, based on the compounds as a single group’’.286 Ni compounds. Based on our analysis, consistent views of the most Although the precise Ni compound (or we are unable to delist oil-fired EGUs. authoritative scientific bodies (i.e., NTP compounds) responsible for the carcinogenic effects in humans is not 3. Ni Risk in their 12th ROC, IARC, and other international agencies) that consider Ni always clear, studies indicate that Ni Comment: Several commenters stated compounds to be carcinogenic as a sulfate and the combinations of Ni that the assumptions regarding the group. sulfides and oxides encountered in the speciation and carcinogenic potential of 3. To make the same assumptions as Ni refining industries cause cancer in Ni compounds used in EPA’s inhalation in option 2, but considering alternative humans. There have been different risk assessment of the case study UREs derived by the CDHS or TCEQ. views on whether or not Ni compounds, facilities are overly conservative and In responding to these peer review as a group, should be considered as likely to overstate the risks. With questions, two of the reviewers agreed carcinogenic to humans. Some authors respect to Ni speciation, the with the views of the most authoritative commenters stated that there are scientific bodies, which consider Ni 283 International Agency for Research on Cancer substantial uncertainties regarding the (IARC), 1990. IARC monographs on the evaluation of carcinogenic risks to humans. Chromium, nickel species of Ni being emitted and the risk 279 U.S. EPA, 2011c. and welding. Vol. 49. Lyons, France: International of such emissions, and that EPA has 280 U.S. EPA, 1991. Agency for Research on Cancer, World Health made ultraconservative assumptions 281 California Department of Health Services Organization Vol. 49:256. aimed at overestimating the risk. The (CDHS) 1991. Health Risk Assessment for Nickel. 284 International Labour Organization/United commenters stated that assigning the Air Toxicology and Epidemiology Section, Nations Environment Programme, World Health Berkeley, CA. Available online at http:// Organization (WHO), 1991. Nickel. In same carcinogenic potency of Ni oehha.ca.gov/air/toxic_contaminants/html/ Environmental Health Criteria No 108 Geneva. subsulfide to other forms of Ni is overly Nickel.htm. 285 European Commission, Scientific Committee conservative and inconsistent with the 282 Texas Commission on Environmental Quality on Health and Environmental Risks (SCHER), 2006. best available evidence. (TCEQ), 2011. Development Support Document for Opinion on: Reports on Nickel, Human Health part. nickel and inorganic nickel compounds. Available SCHER, 11th plenary meeting of 04 May 2006 Response: The EPA disagrees with the online at http://www.tceq.state.tx.us/assets/public/ http://ec.europa.eu/health/ph_risk/committees/ commenters’ assertion that it is implementation/tox/dsd/final/june11/ 04_scher/docs/scher_o_034.pdf. impossible to give an accurate nickel_&_compounds.pdf. 286 NTP, 2011.

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believe that water soluble Ni, such as Ni Nevertheless, taking into account that existing test data for utility and sulfate, should not be considered a there are potential differences in industrial boilers indicate that Cr(VI) is, human carcinogen, based primarily on a toxicity and/or carcinogenic potential on average, 12 percent of total Cr from negative Ni sulfate 2-year NTP rodent across the different Ni compounds, and coal-fired boilers. This document bioassay (which is different than the given that there have been two URE underwent peer review by three external positive 2-year NTP bioassay for Ni values derived for exposure to mixtures reviewers, and all three reviewers subsulfide).287 288 289 Although these of Ni compounds that are 2–3 fold lower considered EPA’s use of the values to be authors agree that the epidemiological than the IRIS URE for Ni subsulfide, the reasonable given the limited data data clearly supports an association EPA also considers it reasonable to use available for Cr speciation profiling. The between Ni and increased cancer risk, a value that is 50 percent of the IRIS EPRI inhalation study for coal-fired they sustain that the data are weakest URE for Ni subsulfide for providing an boilers also used the 12 percent value. regarding water soluble Ni. A recent estimate of the lower end of a plausible The EPA also disagrees that units review 290 highlights the robustness and range of cancer potency values for were assumed to operate 100 percent of consistency of the epidemiological different mixtures of Ni compounds. the time. The dispersion modeling evidence across several decades performed for the case study facilities 4. Cr Risk showing associations between exposure used hourly heat input as a to Ni and Ni compounds (including Ni Comment: One commenter stated temporalization factor for estimating sulfate) and cancer. there are several problems with EPA’s hourly emissions, and in some cases Based on the views of the major analysis related to the fact that Cr hourly heat inputs (and emissions) were scientific bodies mentioned above, and emissions were evaluated as being zero or very low. The commenter those of expert peer reviewers that entirely Cr(VI). The commenter stated provided no data or information to commented on EPA’s approaches to risk that not all of the emitted Cr will remain support their claim that the dispersion characterization of Ni compounds, the in the hexavalent form by the time it modeling EPA used is biased towards EPA considers all Ni compounds to be reaches the target population, and that overestimating downwind impacts. carcinogenic as a group and does not some may be converted to the much less The EPA disagrees with the consider Ni speciation or Ni solubility toxic (and noncarcinogenic) trivalent commenters’ assertion that ‘‘real to be strong determinants of Ni species. The commenter also stated that exposure concentrations for all people carcinogenicity. With regards to non- the concentration levels considered in within a census block’’ must be cancer effects, comparative quantitative the case study assessment are far below considered because it runs counter to analysis across Ni compounds indicates occupational levels. The commenter the long-standing approach that EPA that Ni sulfate is as toxic or more toxic concluded that EPA’s cancer estimates has taken to estimate the maximum than Ni subsulfide or Ni oxide.291 292 should, therefore, be looked on with individual risk, or MIR. The MIR is Regarding the second charge question, some skepticism. Another commenter defined by EPA’s Benzene NESHAP two of the reviewers suggested using the stated that EPA’s estimate of 12 percent regulation of 1989 294 and codified by URE derived by TCEQ for all Ni Cr(VI) from coal-fired EGUs is CAA section 112(f) as the lifetime risk compounds as a group, rather than the unsupported, and that EPA failed to for a person located at the site of one derived by IRIS specifically for Ni recognize that Cr(VI) is highly water- maximum exposure 24 hours a day, 365 subsulfide. The third reviewer did not soluble and is easily reduced to Cr(III) days a year for 70 years (e.g., census comment on alternative approaches. in the presence of SO2 in a low pH block centroids). The MIR is the metric The EPA decided to continue using 100 environment. The resulting Cr(III) associated with the determination of percent of the current IRIS URE for Ni would be expected to precipitate out in whether or not a source category may be subsulfide because IRIS values are at the a FGD. The commenter stated that the delisted from regulatory consideration top of the hierarchy with respect to the actual amount of Cr(VI) that would be under CAA section 112(c)(9). The MIR dose response information used in present in the emissions from an EGU is the risk metric used to characterize EPA’s risk characterizations, and with a wet scrubber is likely to be far the inhalation cancer risks associated because of the concerns about the lower than the 12 percent estimate made with the case study facilities. The EPA potential carcinogenicity of all forms of by EPA. used the annual average ambient air Ni raised by the major national and Several commenters questioned the concentration of each HAP at each international scientific bodies. validity of the chronic inhalation study census block centroid as a surrogate for by EPA because of (1) the use of the lifetime inhalation exposure 287 Oller A. Respiratory carcinogenicity surrogate speciated Cr emissions data concentration of all the people who assessment of soluble nickel compounds. Environ instead of actual emissions data, (2) the reside in the census block. The EPA has Health Perspect. 2002, 110:841–844. assumption that units were run 100 288 Heller JG, Thornhill PG, Conard BR. New used this approach to estimate MIR views on the hypothesis of respiratory cancer risk percent of the time which is impossible, values in all of its risk assessments to from soluble nickel exposure; and reconsideration (3) dispersion modeling was used that is support risk-based rulemakings under of this risk’s historical sources in nickel refineries. biased towards over predicting CAA section 112 to date. J Occup Med Toxicol. 2009, 4:23. downwind impacts, and (4) estimated 289 Goodman JE, Prueitt RL, Thakali S, and Oller 5. Acid Gas Risk AR. The nickel iron bioavailability model of the ambient concentrations were utilized as carcinogenic potential of nickel-containing substitutes for real exposure Comment: One commenter stated that substances in the lung. Crit Rev Toxicol. 2011, concentrations for all people within a acid gas emissions from oil-fired EGUs 41:142–174. census block. are not of the magnitude that triggered 290 Grimsrud TK and Andersen A. Evidence of Response: The EPA disagrees with the EPA’s decision to regulate EGUs in carcinogenicity in humans of water-soluble nickel salts. J Occup Med Toxicol. 2010. 5:1–7. Available commenters’ assertion that all Cr was general, raising the question of whether online at http://www.ossup-med.com/content/5/1/7. considered to be hexavalent. As reduction (or even total elimination) of 291 Haber LT, Allen BC, Kimmel CA. Non-Cancer discussed in ‘‘Methods to Develop acid gas emissions from oil-fired EGUs Risk Assessment for Nickel Compounds: Issues Inhalation Cancer Risk Estimates for could have any significant effect on Associated with Dose-Response Modeling of 293 Inhalation and Oral Exposures. Toxicol Sci. 1998. Chromium and Nickel Compounds,’’ EPA’s goals of reducing non-cancer 43:213–229. 292 NTP, 1996. 293 U.S. EPA, 2011c. 294 54 FR 3804.

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health risk or acidification of sensitive reevaluate its assessment and to (1) 5 years of recent meteorological data ecosystems in the U.S. undertake more refined (Tier 3) risk from the weather station nearest to each Several commenters stated that acid assessment for any facility of concern. facility, rather than one year of gas concentrations estimated in the case meteorological data. This is more Several commenters stated that for non- representative of long-term (i.e., lifetime) study facility assessment and the Utility Hg HAP EPA produced one study on exposures and risks. Study do not exceed human health chronic inhalation risk assessment that (2) Temporally-varying emissions based on thresholds of concern. Two commenters identified three sites with cancer risks continuous emissions monitoring data, rather stated that HCl emissions are negligible greater that one in a million for Cr(VI), than assuming a constant emission rate for compared to other primary emissions which was authored by EPA staff and each facility throughout the entire (such as SO2) that can lead to potential not peer reviewed. One commenter simulation. acidification of ecosystems. stated that EPA study is based on (3) Building downwash, where appropriate. Response: We do not agree with misinformation and overestimates commenter’s implication that Congress (4) The latest version of AERMOD [version assumptions, and that EPA has no data 11103]. intended EPA to regulate only those demonstrating health impacts from EGU The EPA’s assessment of the case HAP emissions from U.S. EGUs for emissions of non-Hg HAP, or the benefit study facilities for the proposed rule which an appropriate and necessary from reducing such emissions. Two concluded that three coal-fired facilities finding is made, and commenter has commenters stated that no benefits will and one oil-fired facility had estimated cited no provision of the statute that be derived from the non-Hg HAP lifetime cancer risks greater than one in states a contrary position. The EPA emission reductions associated with the a million. For the final rule, revisions concluded that we must find it proposed rule because no non-Hg HAP were made to the case studies based on ‘‘appropriate’’ to regulate EGUs under health risks were proven, and that no comments received, and the results CAA section 112 if we determine that a showing was made that EGU non-Hg indicate that five coal-fired facilities and single HAP emitted from EGUs poses a HAP emission levels reach levels one oil-fired facility had estimated hazard to public health or the associated with adverse health effects. environment. If we also find that lifetime cancer risks greater than one in Another commenter stated that EPA a million. regulation is necessary, the Agency is must complete a comparable and authorized to list EGUs pursuant to Regarding peer review, the risk separate national-scale risk assessment assessment methodology used by EPA CAA section 112(c) because listing is for non-Hg metals in order to determine the logical first step in regulating source for the case studies was consistent with appropriateness of proposing emissions the method that EPA uses for categories that satisfy the statutory standards for non-Hg metals. criteria for listing under the statutory assessments performed for Risk and Response: The commenters are framework of CAA section 112. See New Technology Review rulemakings, which incorrect in the assertion that EPA’s Jersey, 517 F.3d at 582 (stating that underwent peer review by the Science case studies were performed with less ‘‘[s]ection 112(n)(1) governs how the Advisory Board in 2009.296 The SAB rigor than the EPRI analysis. The EPRI Administrator decides whether to list issued its peer review report in May analysis used a tiered approach to risk EGUs * * *’’). As we noted in the 2010. The report generally endorsed the assessment, beginning with Tier 1 using preamble to the proposed rule, D.C. risk assessment methodologies used in EPA’s SCREEN3 dispersion model on all Circuit precedent requires the Agency to the program. In addition, in July 2011, regulate all HAP from major sources of 470 coal-fired power plants in the U.S., the EPA completed a letter peer review HAP emissions once a source category and following with Tier 2 with EPA’s of the methods used to develop is added to the list of categories under Human Exposure Model (which uses the inhalation cancer risk estimates for Cr CAA section 112(c). National Lime AERMOD dispersion model) for plants and Ni compounds. with higher risks from the Tier 1 Ass’n v. EPA, 233 F.3d 625, 633 (D.C. f. Ecosystem Impacts From HAP Cir. 2000). 76 FR 24989. The EPA modeling. Although tiered risk discusses in the preamble to the assessment is an appropriate approach, Comment: Two commenters assert proposed rule and this final action its the Tier 2 modeling could have been that EPA is not justified in regulating concerns with HCl and other acid gas more refined. For example, more acid gases based on concern about the HAP emissions from EGUs and the meteorological data could have been potential that acid gases contribute to Agency’s approach for establishing used and building downwash could ecosystem acidification rather than section 112(d) standards for acid gas have been considered. The EPRI concerns about hazards to public health. HAP. analysis ostensibly concluded that the The commenters further claim that Tier 2 modeling with HEM was HCl’s contribution to ecosystem 6. EPRI Risk Analysis conservative, and that because the acidification is de minimis. The Comment: Two commenters stated modeled risks did not exceed certain commenters point out that EPA that a comprehensive tiered inhalation thresholds, no further refinement was acknowledges uncertainty in risk assessment (the EPRI study) using necessary. However, such refinements quantification of acidification and EPA EPA-prescribed methods with improved could result in higher modeled risks relies on recently published research 297 emission factors, fuel data, and than those from the commenter’s Tier 2 that is irrelevant to the question since it confirmed stack parameters did not modeling. is based on research conducted in the identify significant health risks (cancer The EPA’s dispersion modeling of the peat bog ecosystem in the United or non-cancer) among U.S. coal-fired case study facilities was actually Kingdom. Another commenter calls power plants (as they existed in 2007). performed with a greater degree of attention to several new studies The commenters noted that these results refinement than the EPRI analysis, and published in a special issue of the contrast with those presented by EPA was consistent with EPA’s Guideline on for its non-Hg case studies on 16 (15 Air Quality Models.295 296 U.S. EPA–SAB, 2010. coal-fired) power plants. The In contrast to the approach used in 297 Evans, Chris D., Don T. Monteith, David the EPRI analysis, the EPA used: Fowler, J. Neil Cape, and Susan Brayshaw. 2011. commenters stated that several issues ‘‘Hydrochloric Acid: An Overlooked Driver of appear to underlie these differences, Environmental Change.’’ Environmental Science & indicating the need for EPA to 295 Appendix W to 40 CFR Part 51. Technology 45 (5), 1887–1894.

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journal Ecotoxicology devoted to the preamble to the proposed rule, the EPA intended to protect the public, effects of MeHg on wildlife. agrees that there are potential including sensitive populations, against Response: Although EPA agrees that environmental risks from exposures of exposures to Hg from EGUs that would quantification of acidification effects ecosystems through Hg and non-Hg exceed the level determined by the EPA has remaining uncertainty, the science HAP deposition. The EPA cited relevant to be without appreciable risk, e.g., and methodology has progressed in articles from the special edition of exposures that are above the RfD for recent years. Based on recent peer Ecotoxicology 302 mentioned by the methylmercury (MeHg), or would reviewed research including Evans et commenter in the ecosystem effects contribute additional risk in areas where al.,298 acid gases can significantly section on Chapter 5 of the RIA for this Hg exposures exceed the RfD due to contribute to acidification. The EPA rule, which is available in the docket. contributions from all sources of Hg. published a comprehensive risk G. EPA Affirms the Finding That It Is Our recent technical analyses show that assessment of acidification effects of Appropriate and Necessary to Regulate 98 percent of the watersheds for which 299 nitrogen and sulfur deposition and a EGUs To Address Public Health and we had fish tissue data have total Hg 300 policy assessment. Given the extent Environmental Hazards Associated deposition such that potential exposures and importance of the sensitive With Emissions of Hg and Non-Hg HAP exceed the MeHg RfD, above which ecosystems evaluated in the review of From EGUs there is an increased risk of adverse nitrogen and sulfur deposition any effects on human health. In these substance that contributes to further In response to peer reviews of both watersheds, any reductions in exposures acidification must be considered to be the Hg and non-Hg HAP risk analyses, to Hg will reduce risk, and thus the affecting the public welfare. The EPA and taking into account public incremental contribution to Hg exposure disagrees that the peer reviewed study comments, the EPA conducted revised from any individual source or group of mentioned by commenter by Evans et analyses of the risks associated with sources, such as EGUs, may reasonably al., (2011) is not relevant to U.S. emissions of Hg and non-Hg HAP from be anticipated to cause additional risk. U.S. EGUs. These revised analyses ecosystems. The paper presents As we have explained, in calculating demonstrated that the risk results evidence that show (1) that HCl is the estimates described above, the EPA reported in the preamble to the highly mobile in the environment, has used peer-reviewed methods, and proposed rule are robust to revisions in transferring acidity easily through soils focused on populations likely to be at response to the peer reviews and public and water, (2) that HCl can transport higher risk of exposure to Hg from U.S. longer distances than previously comments. Specifically, the revised Hg Risk TSD EGUs, e.g., female subsistence fishing thought (given its presence in remote shows that up to 29 percent of modeled populations consuming at the 99th ecosystems, and (3) that it can be a watersheds have populations potentially percentile fish consumption rate. The larger driver of acidification than at-risk from exposure to Hg from U.S. EPA did not, however, use the most previously thought. The fact that this EGUs.303 This 29 percent of watersheds conservative assumptions that would study took place in the U.K. is itself with populations potentially at-risk lead to upper bound risk estimates. As irrelevant. The chemical interactions of includes up to 10 percent of modeled discussed above and in the revised Hg HCl in water are the same the world watersheds where deposition from U.S. Risk TSD, we did not use the highest over and sensitive ecosystems exist in EGUs alone leads to potential exposures fish tissue cooking loss adjustment the U.S. as well as in Europe as that exceed the MeHg RfD, and up to 24 factor that was reported in the literature, illustrated in the ecological risk percent of modeled watersheds where which, had we done so, would have 301 assessment for NOX and SOX. total potential exposures to MeHg increased the estimates of Hg exposure Furthermore, the commenter is factually exceed the RfD and U.S. EGUs substantially. Thus, we believe our incorrect that EPA is justifying that it is contribute at least 5 percent to Hg analysis could understate risk to the appropriate and necessary to regulate deposition. Each of these results most exposed individual, noting that we HAP emissions from EGUs based on this independently supports our conclusion have focused on the 99th percentile one study. The EPA agrees with the that U.S. EGUs pose hazards to public consumption rate in our estimates. commenter that Hg exposure in wildlife health. Further, we were able to assess is responsible for various adverse health In the preamble to the proposed rule potential Hg exposures in only a small effects in many species across the U.S. and in the 2000 finding, the EPA subset of generally representative and recognizes that research is ongoing explained at length the serious nature of watersheds in the U.S. because our in this area. As discussed in the the health effects associated with Hg analysis was necessarily premised on exposures, and the persistent nature of those water bodies for which we had 298 Id. Hg in the environment. Congress fish tissue Hg samples. Specifically, we 299 U.S. Environmental Protection Agency (U.S. specifically recognized the significant EPA). 2009. Risk and Exposure Assessment for analyzed 3,141 of the approximately Review of the Secondary National Ambient Air impacts of persistent bioaccumulative 88,000 watersheds in the United States. Quality Standards for Oxides of Nitrogen and pollutants, like Hg, when it enacted This limited set of watersheds excludes Oxides of Sulfur (Final). EPA–452/R–09–008a. section 112(c)(6), which requires the several of the watersheds with the Office of Air Quality Planning and Standards, EPA to subject source categories listed Research Triangle Park, NC. September. Available highest U.S. EGU attributable on the Internet at http://www.epa.gov/ttn/naaqs/ pursuant to that section to MACT deposition, and may also not have standards/no2so2sec/data/NOxSOxREASep2009 standards. Congress also required included watersheds with the highest MainContent.pdf. certain studies be conducted under CAA sensitivity to Hg deposition, e.g., the 300 U.S. Environmental Protection Agency (U.S. section 112(n) regarding the health highest methylation rates (see above). EPA). 2011d. Policy Assessment for the Review of effects of Hg. The EPA interprets CAA the Secondary National Ambient Air Quality Nevertheless, our analysis of the subset Standards for Oxides of Nitrogen and Oxides of section 112(n)(1), with regard to Hg, as of watersheds we examined Sulfur. EPA–452/R–11–005a. Office of Air Quality demonstrates that almost one third of Planning and Standards, Research Triangle Park, 302 Ecotoxicology 17:83–91, 2008. the watersheds are estimated to have Hg NC. February. Available on the Internet at http:// 303 This corresponds to 28 percent of modeled deposition attributable to U.S. EGUs www.epa.gov/ttnnaaqs/standards/no2so2sec/data/ watersheds with populations potentially at-risk in 20110204pamain.pdf. the analysis reported in the preamble to the that contributes to potential exposures 301 U.S. EPA, 2009. proposed rule. above the MeHg RfD. The SAB

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confirmed that the subset of watersheds in a million, (2) the number of coal-fired CAA section 112 because the only way we examined is sufficient. EGU facilities with cancer risks greater to ensure permanent reductions in HAP Considering these points and the than 1 in a million has increased from emissions from U.S. EGUs and the information on Hg in the record, the 3 to 5, and (3) the highest risk coal-fired associated risks to public health and the EPA believes that 10 percent of facility still has cancer risks of 5 in a environment is through standards set watersheds with populations at risk due million, which is above the 1 in a under CAA section 112. While CSAPR to U.S. EGU emissions alone is million benchmark, we conclude that is projected to achieve some Hg unacceptable, as is 24 percent of the finding that emissions of non-Hg reductions due to co-control of Hg watersheds with populations at risk due HAP from U.S. EGUs pose a hazard to provided by controls put in place to to U.S. EGU contributions in public health is confirmed by the achieve required reductions in SO2 conjunction with total deposition from revised non-Hg risk inhalation case emissions, the results of the revised Hg other sources. Taking into account the studies. Risk TSD indicate that an unacceptable percentage of watersheds at risk, and the Moreover, some HAP emissions from percentage of modeled watersheds have potential for even higher percentages to U.S. EGUs contribute to adverse populations potentially at-risk from U.S. be at risk using more conservative risk ecosystem effects. While we did not do EGU-attributable Hg deposition would assumptions and a more complete new analyses on these topics, we remain after implementation of CSAPR. coverage of high U.S. EGU Hg reiterate that (1) Hg emissions from U.S. While we modeled slightly higher Hg deposition watersheds, the EPA EGUs pose a hazard to the environment, emissions from U.S. EGUs (i.e., 29 tons concludes that Hg emissions from U.S. contributing to adverse impacts on fish- of Hg) in our risk analysis compared to EGUs pose a hazard to public health. eating birds and mammals, (2) Hg is a the most recent estimate of 27 tons, we Given these findings, and considering persistent bioaccumulative do not believe this 2 ton difference that (1) the revised risk analysis showed environmental contaminant, and as a would substantially change our finding the percent of modeled watersheds with result, failing to control Hg emissions that Hg emissions from U.S. EGUs pose populations potentially at-risk increased from U.S. EGU sources will result in a hazard to public health or the Hg risks from 28 to 29 percent, and (2) the long-term environmental loadings of Hg, reported in the preamble to the revised analysis includes 36 percent above and beyond those loadings caused proposed rule, as this represents less more watersheds, which significantly by immediate deposition of Hg within than a 10 percent reduction in Hg expands the coverage in several states, the U.S.; controlling Hg emissions from emissions. In addition, the actual we conclude that the finding that U.S. EGUs helps to reduce the potential reductions in Hg that will occur due to emissions of Hg from U.S. EGUs pose a for environmental hazard from Hg now application of controls to meet the SO2 hazard to public health is confirmed by and in the future, and (4) it is emissions requirements of CSAPR may the national-scale revised Hg Risk TSD. appropriate to regulate those HAP differ from those projected to occur, due As a result, we conclude that it remains which are not known to cause cancer to differences in the technologies that appropriate to regulate Hg emissions but are known to contribute to chronic individual EGU sources choose to from U.S. EGUs because those Hg non-cancer toxicity and environmental install. The only way to ensure emissions pose a hazard to public degradation, such as the acid gases. In reductions in Hg, including those health. addition, we have identified effective modeled as resulting from the CSAPR, With regards to the revised non-Hg controls available to reduce Hg and non- is to directly regulate Hg emissions inhalation case studies, the highest Hg HAP emissions. under CAA section 112. estimated individual lifetime cancer risk In summary, we confirm the findings In summary, we confirm the findings for the one case study facility (out of 16) that Hg and non-Hg HAP emissions that it is necessary to regulate HAP with oil-fired EGUs is estimated to be 20 from U.S. EGUs each pose hazards to emissions from U.S. EGUs because in a million, driven by Ni emissions. For public health and that it remains (1) the national-scale Hg Risk TSD the facilities with coal-fired EGUs, there appropriate to regulate U.S. EGUs under shows that the hazards to public health were five (out of 16) with maximum CAA section 112 for those reasons. We posed by Hg emissions from U.S. EGUs individual cancer risks greater than one also conclude that it remains will not be addressed through in a million (the highest was five in a appropriate to regulate EGUs under imposition of the CAA, (2) we cannot be million), four of which were driven by CAA section 112 because of the certain that the identified cancer risks emissions of Cr(VI), and one of which magnitude of Hg and non-Hg emissions attributable to U.S. EGUs will be was driven by emissions of Ni. and the environmental effects of Hg and addressed through imposition of the Therefore, a total of six facilities exceed some non-Hg emissions, each of which requirements of the CAA, (3) the the criterion for EGUs to be regulated standing alone, supports the appropriate environmental hazards posed by under CAA section 112. There were also finding. The availability of controls to acidification will not be fully addressed two facilities with coal-fired EGUs with reduce HAP emissions from EGUs only through imposition of the CAA, (4) maximum individual cancer risks at one further supports the appropriate finding. regulation under CAA section 112 is the in a million. In the preamble to the Our revised analyses still show that in only way to ensure that all HAP proposed rule, we reported that the 2016 after implementation of other emissions reductions that have been maximum individual lifetime cancer provisions of the CAA, HAP emissions achieved since 2005 remain permanent, risk for the one facility with oil-fired from U.S. EGUs are reasonably and (5) direct control of Hg emissions EGUs was estimated to be 10 in a anticipated to pose hazards to public affecting U.S. deposition is only million, and that there were 3 coal-fired health; therefore, it is necessary to possible through regulation of U.S. EGU facilities with maximum regulate EGUs under CAA section 112. emissions as we are unable to control individual cancer risks greater than 1 in Moreover, HAP emissions from U.S. global emissions directly. All of these a million (the highest was 8 in a EGUs are expected to continue to findings independently support a million), and 1 coal-fired EGU facility contribute to adverse ecosystem effects. finding that it is necessary to regulate with maximum individual cancer risks In addition, based on evaluation of the U.S. EGUs under CAA section 112. equal to 1 in a million. Given that (1) regulations required by the CAA, Based on these findings, the Agency the lifetime cancer risk for the oil-fired including the recent CSAPR, it is affirms its finding that it remains EGU facility has increased from 10 to 20 necessary to regulate U.S. EGUs under appropriate and necessary to regulate

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coal- and oil-fired EGUs under CAA The EPA has the discretion to delete 112(c)(9)(B) and NRDC, we are denying section 112, and maintains that the a source category under CAA section the delisting petition. inclusion of coal- and oil-fired EGUs on 112(c)(9)(B), but only if EPA concludes 2. Even Assuming, for the Sake of the CAA section 112(c) list of source that the relevant requirements of CAA Argument, That EPA Could Delist a categories regulated under CAA section section 112(c)(9)(B) have been met. HAP Portion of a Source Category, UARG has 112 remains valid. emissions from EGUs present both Failed to Meet the Requirements of CAA IV. Denial of Delisting Petition cancer risks, which implicate the Section 112(c)(9) requirements of CAA section During the comment period on the 112(c)(9)(B)(i), and non-cancer human Even assuming, for the sake of proposed rule, UARG submitted a health effects or adverse environmental argument, that EPA could delist a petition pursuant to CAA section effects, which implicate the portion of a source category that emits 112(c)(9), asking the Agency to delete a requirements of CAA section carcinogens, which it cannot, UARG has portion of the EGU source category from 112(c)(9)(B)(ii). As such, UARG bears failed to demonstrate that the the list of source categories to be the burden of demonstrating that the requirements for delisting in CAA regulated under CAA section 112. requirements of both clauses are met. section 112(c)(9)(i) and (ii) have been Specifically, UARG asks that EPA delist met. UARG contends that it used EPA’s coal-fired EGUs from the CAA section B. Rationale for Denying UARG’s models and approaches, as well as the 112(c) source category list. A copy of Delisting Petition most recent data. We have carefully UARG’s petition has been placed in the The EPA is denying UARG’s petition reviewed UARG’s analyses, however, docket for today’s rulemaking, along to delist EGUs from the CAA section and found certain flaws that we believe with the analysis conducted by EPRI 112(c) source category list. UARG bias their risk results low. Specifically, that UARG uses to support its petition improperly seeks to delist a portion of we identified flaws in emissions (hereinafter referred to as UARG’s a CAA section 112(c) listed source estimation. UARG developed estimates analysis). In support of its petition, category that emits carcinogens, which for all EGU facilities using data which pre-date the 2010 ICR emissions UARG asserts that: (1) No coal-fired is contrary to the plain language of CAA EGU or group of coal-fired EGUs will measurement data that EPA obtained to section 112(c)(9). Even setting aside this emit HAP in amounts that will cause a support this rule. UARG also relied fundamental defect, UARG has failed to lifetime cancer risk greater than one in upon an emissions equation developed meet the requirements of CAA section one million; and (2) no coal-fired EGU by EPRI and DOE to develop its metal 112(c)(9)(B). or group of coal-fired EGUs will emit emissions estimates. With regard to that non-carcinogenic HAP in amounts that 1. UARG’s Attempt to Delist a Portion approach, the EPA analysis of the ICR will exceed a level which is adequate to of a Listed Source Category Conflicts data has found that the regression protect public health with an ample With D.C. Circuit Precedent approach is not a good predictor of margin of safety or cause adverse actual EGU emissions. Furthermore, we environmental effects. We disagree with In December 2000, the EPA listed found fault with their use of the UARG’s assertions and for the reasons coal- and oil-fired EGUs as a single geometric mean and their outlier set forth below are denying UARG’s source category. UARG asks the Agency analysis for computing emission factors. petition to delist coal-fired EGUs from to delist a portion of that listed source The EPA analysis has found that the the section 112(c) source category list. category: Coal-fired EGUs. UARG’s geometric mean approach underpredicts request conflicts, however, with D.C. actual emissions by an average of more A. Requirements of CAA Section Circuit precedent, which provides that than seventy percent. This had an 112(c)(9) for categories, like EGUs, that pose especially large impact on the arsenic, CAA section 112(c)(9)(B) provides cancer risks, the EPA may not delist a chromium, and nickel emissions that ‘‘[t]he Administrator may delete portion of a source category. NRDC v. estimates. These and other issues are any source category’’ from the section U.S. EPA, 489 F.3d 1364 (D.C. Cir. explained in further detail in the 112(c) source category list if the Agency 2007). Specifically, in NRDC, the D.C. response to comments document. As a determines that: (i) For HAP that may Circuit held that the Agency’s attempt to result, we believe the resulting risk cause cancer in humans, ‘‘no source in delist a ‘‘low-risk’’ subcategory was estimates in UARG’s analysis are biased the category (or group of sources in the ‘‘contrary to the plain language of the low. In addition, we note that there are case of area sources) emits such statute,’’ and that the statute only dispersion model refinements that are hazardous air pollutants in quantities authorized the agency to remove source not included in the UARG analyses, but which may cause a lifetime risk of categories pursuant to section 112(c)(9). were included in EPA’s analysis. For cancer greater than one in one million Id. at 1373 (‘‘Because EPA’s example, for the dispersion modeling of to the individual in the population who interpretation of Section 112(c)(9) as the 16 non-Hg case studies, the EPA is most exposed to emissions of such allowing it to exempt the risk-based considered building downwash and pollutants from the source (or group of subcategory is contrary to the plain used time-varying emissions, neither of sources in the case of area sources)’’; language of the statute, the EPA’s which were used in UARG’s analysis. and (ii) for HAP that may result in interpretation fails at Chevron step These factors could also bias the UARG human health effects other than cancer one.’’). risk estimates low. or adverse environmental effects, ‘‘a UARG’s request is indistinguishable However, even taking UARG’s determination that emissions from no from the situation before the court in analysis at face value and accepting, for source in the category or subcategory NRDC. UARG does not seek to delist arguments’ sake, their assumptions and concerned (or group of sources in the coal- and oil-fired EGUs, which is the emissions estimates, UARG’s own data case of area sources) exceed a level source category that EPA listed, but supports denial of the petition because which is adequate to protect public rather a portion of that category. UARG UARG itself identifies a maximum health with an ample margin of safety also does not dispute that coal-fired individual cancer risk exceeding 1 in a and no adverse environmental effect EGUs emit carcinogenic HAP. Because million, which is the statutory threshold will result from emissions from any UARG’s request to delist is contrary to in CAA section 112(c)(9)(B)(i). source.’’ the plain language of CAA section Specifically, UARG’s multi-pathway

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model plant ingestion risk analysis conclusions in UARG’s analysis, UARG Hg inhalation risks from 16 EGU facility concluded that adult anglers would face only evaluated the non-cancer case studies, including both coal- and cancer risks of 4 in a million. For this inhalation risks associated with each oil-fired EGUs, as part of its technical reason alone, the petition should be EGU facility. It did not conduct a analyses supporting the appropriate and denied. similar analysis to assess multipathway necessary finding. That analysis UARG dismisses the 4 in a million risks for each EGU facility. Instead, it demonstrates that there are 6 EGU cancer result, arguing that the refined conducted a model plant analysis and facilities (of the 16 that we analyzed) model plant multipathway risk admits that such model plant does not with cancer risks exceeding one in one assessment that it conducted is ‘‘overly represent the worst-case scenario for million. These cancer risk levels exceed conservative.’’ UARG conducted its noncancer human health risks from any the delisting criteria set forth in CAA multi-pathway risk analysis to evaluate EGU. Thus, the analysis fails to fully section 112(c)(9)(B)(i), and confirm that the risks associated with ingesting characterize noncancer multipathway EGUs must remain a listed source persistent and bioaccumulative HAP risks for the source category, and category. As explained above, some which are emitted into the atmosphere UARG’s petition must be denied on this commenters assert that EPA’s analysis and subsequently deposit into the basis as well. of non-Hg inhalation risks from EGUs environment and bioaccumulate in Finally, UARG failed to meet its conducted in support of the proposal for animals which are eventually consumed burden of showing that ‘‘no adverse this rulemaking overstated emissions as food. Instead of conducting this environmental effect will result from from, and risks associated with, EGUs. multipathway analysis for each EGU emissions from any source’’ pursuant to These commenters argue that the facility, UARG instead analyzed multi- CAA section 112(c)(9)(B)(ii). UARG analysis supporting UARG’s petition pathway risks by evaluating a single analyzed environmental effects only in more appropriately assesses EGU risk. model plant. Nothing in the record conjunction with its model plant. The EPA disagrees with these comments indicates, however, that UARG’s model Because UARG’s model plant does not and addresses these comments in plant represents the worst-case scenario represent the worst-case scenario for section III above. for cancer human health risks from any environmental effects, UARG’s analysis Significantly, the EPA based its EGU. Indeed, although UARG claims in falls short and fails to characterize fully analysis of 16 case study EGUs directly its petition that the site selected for its the potential environmental impacts, on the 2010 emissions test data from case study is ‘‘likely as close to a worst- and UARG’s petition must be denied. EGUs obtained through the ICR. The case scenario as is possible given the For all of these reasons, the EPA EPA’s 16 case study analysis used numerous variables associated with denies UARG’s petition to delist coal- emissions data either taken directly ingestion pathway risks’’ (UARG fired EGUs from the CAA section 112(c) from the 2010 emissions test data, or petition at 12), the supporting source category list. derived using emissions factors based documentation for that case study C. EPA’s Technical Analyses for the on the 2010 data for similar EGU units. specifically acknowledges that its Appropriate and Necessary Finding The EPA also included dispersion fictional model plant scenario ‘‘is not Provide Further Support for the model refinements in its final case intended to represent the risk due to Conclusion That Coal-Fired EGUs studies, as noted above. Further, the emissions from an actual plant or the Should Remain a Listed Source EPA re-analyzed the 16 case studies that highest level of risk that could be Category we conducted for the proposal and associated with a coal-fired power plant revised those analyses consistent with at any location’’ (EPRI at 1). The statute The EPA reasonably concluded in new non-Hg HAP emissions data and requires that no source in the category December 2000, based on the corrected stack parameters provided by may cause a lifetime cancer risk greater information available to the Agency at commenters (including UARG) during than one in one million to the most that time, that it was appropriate and the comment period on the proposed exposed individual, and UARG has necessary to regulate coal- and oil-fired rule. The EPA received revised failed to make this showing. UARG has EGUs under CAA section 112 and added information concerning emissions tests, neither modeled multi-pathway risks for such units to the list of source categories stack heights and stack diameters for a worst-case model facility, nor subject to regulation under CAA section some of the case study EGU facilities. evaluated the multipathway risks 112(d). As discussed in section III The EPA incorporated all of these associated with each individual EGU above, the EPA conducted additional, corrections into our analysis and then facility. Accordingly, UARG has not extensive technical analyses based on re-analyzed the risks for the 16 case made the demonstration required by recent data that confirm it remains study facilities. When completed, the CAA section 112(c)(9)(B)(i). But, even appropriate and necessary to regulate EPA determined that the corrections focusing on the multi-pathway risk HAP from coal- and oil-fired EGUs, incorporated into the reanalysis had analysis that UARG did conduct, which because such EGUs continue to pose little effect on the overall results. In the admittedly does not represent a worst- hazards to public health. HAP emissions final rule, the EPA concludes that the case facility, UARG’s analysis still from coal- and oil-fired EGUs also maximum individual inhalation cancer shows cancer risks greater than one in continue to cause adverse risks for 6 out of the 16 case study EGU a million. Accordingly, UARG’s petition environmental effects. UARG advances facilities are greater than 1 in a million. must be denied. several arguments, challenging the These cancer risk levels confirm that Although it is not necessary to reach analyses the Agency completed in EGUs do not satisfy the delisting the requirements of CAA section support of the proposed rule. We criterion of CAA section 112(c)(9)(B)(i) 112(c)(9)(B)(ii) that address non-cancer address those arguments in section III and thus should remain a listed source human health risks, we note that UARG above. The Agency’s analyses category. has also failed to show that ‘‘emissions supporting the appropriate and The EPA’s national-scale Hg Risk TSD from no source in the category * * * necessary finding confirm that EGUs supporting the appropriate and exceed a level which is adequate to cannot be delisted pursuant to CAA necessary finding also confirm that Hg protect public health with an ample section 112(c)(9). emissions from coal- and oil-fired US margin of safety.’’ Again, even Specifically, as explained further in EGUs are reasonably anticipated to pose accepting, for argument’s sake, the section III above, the EPA analyzed non- a hazard to public health. As discussed

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in section III above, the EPA interprets arguing that EPA cannot consider the developing nervous systems of children CAA section 112(n)(1), with regard to risks posed by EGUs in conjunction during gestation. EGUs remain one of mercury, as intended to protect the with any other risks, including those the largest unregulated sources of Hg public, including sensitive populations, from other source categories. Nothing in emissions, and those emissions against exposures to Hg from EGUs that CAA section 112(c)(9), however, continue to contribute to Hg exposures would exceed the level determined by provides that the Agency cannot and risk. UARG seeks to ignore the fact EPA to be without appreciable risk, e.g., consider background or emissions due that exposures above the RfD exist in exposures that are above the RfD for to other sources. CAA section almost every watershed we modeled, methylmercury (MeHg), or would 112(c)(9)(B)(ii) provides that ‘‘no source and instead focuses on the contribution contribute additional risk in areas where in the category or subcategory provided solely by EGUs. The EPA did Hg exposures exceed the RfD due to concerned (or group of sources in the as UARG asked and found that up to 10 contributions from all sources of Hg. case of area sources) exceed a level percent of modeled watersheds where In order to determine whether EGU which is adequate to protect public deposition from U.S. EGUs alone leads Hg emissions pose a hazard to public health with an ample margin of safety to potential exposures that exceed the health, the EPA conducted a national- and no adverse environmental effect MeHg RfD. Thus, even focusing on EGU scale Hg Risk TSD focused on will result from emissions from any emissions in a vacuum, which we do populations with high levels of self- source.’’ This language could be read to not believe is appropriate or required caught freshwater fish consumption. provide that the Agency consider only under CAA section 112(c)(9), we still The results of the Hg Risk TSD show the risks associated with the source found that up to 10 percent of the that 98 percent of modeled watersheds category at issue, and ignore how those watersheds exceed the RfD due to EGU have total exposures to MeHg that risks fit with real-world exposures.304 emissions even before taking into exceed the MeHg RfD, above which However, the language could also be account the numerous other sources of there is an increased risk of adverse read to provide that the Agency Hg deposition, and we believe this to be effects on human health. In these consider the cumulative effect of HAP an unacceptable percentage of watersheds, any reductions in exposures emissions from the individual sources watersheds above the RfD. Due to the to Hg will reduce risk, and thus the in the category in conjunction with the persistent, bioacccumulative nature of incremental contribution to Hg exposure HAP emissions from other sources. The Hg, among other factors, we believe it is from any individual source or group of latter is a reasonable interpretation, appropriate to consider the combined sources, such as EGUs, may reasonably especially when considering how the impact of Hg emissions from EGUs and be anticipated to cause additional risk. public is exposed to HAP emissions. other sources of Hg. Thus, we also The Hg Risk TSD focused on those Considering the individual sources in a considered the 24 percent of modeled watersheds that either exceeded the RfD source category in isolation treats the watersheds where, even though U.S. based on U.S. EGU attributable sources as if they exist in a vacuum, EGU emissions alone are not enough to deposition alone, without considering which does not mirror reality. Such an cause exposures that exceed the RfD, other sources of deposition, or approach is particularly problematic for those emissions contribute at least 5 watersheds that exceed the RfD due to environmentally persistent HAP that percent of total exposures to MeHg that total Hg deposition and to which U.S. bio-accumulate in the food chain, such exceed the RfD. The combined total of EGUs contributed at least 5 percent of as mercury.305 29 percent of modeled watersheds the Hg deposition. The results of that Here, the record demonstrates that 98 where U.S. EGUs cause or contribute to analysis show that up to 29 percent of percent of the watersheds EPA modeled MeHg exposures above the RfD is the modeled watersheds have have total exposures to MeHg that clearly unacceptable and thus the UARG populations that are potentially at-risk exceed the MeHg RfD, above which petition to delist must be denied. from exposure to Hg from U.S. EGUs, there is increased risk of adverse effects Thus, the technical analyses the including up to 10 percent of modeled on human health, especially on the Agency conducted in support of the watersheds where deposition from U.S. appropriate and necessary finding EGUs alone leads to potential exposures 304 The same is true with respect to section confirm that EGUs should remain a that exceed the MeHg RfD, and up to 24 112(c)(9)(B)(i). listed source category. percent of modeled watersheds where 305 In a prior rulemaking, EPA stated that the total potential exposures to MeHg language in section 112(c)(9)(B)(ii) ‘‘does not direct V. Summary of This Final NESHAP EPA to extend its analysis to either emissions from exceed the RfD and U.S. EGUs other sources in other categories or subcategories or This section summarizes the contribute at least 5 percent to Hg to non-attributable background concentrations.’’ 71 requirements of the final EGU NESHAP. deposition. This approach to assessing FR 8347 (Feb. 16, 2006). The preamble to that rule Section VI below summarizes the national risks from Hg deposition from repeatedly states that the ‘‘focus’’ of the delisting determination in that rule was on emissions from significant changes to this final rule EGUs was supported by the sources in the category under review. See 71 FR following proposal. independent peer review conducted by 8346–47. The preamble went on to compare section the Science Advisory Board, as 112(c)(9)(B) to section 112(f)(2)(A) in a way that A. What is the source category regulated discussed fully in section III. suggested that EPA can consider risks presented by by this final rule? Finally, as discussed in section III, sources other than the subject source category under section 112(f)(2), but not under section This final rule affects coal- and oil- based on this assessment, the EPA has 112(c)(9). We do not believe the language of section fired EGUs. confirmed that Hg emitted from U.S. 112(c)(9) compels any different treatment. The EGUs pose a hazard to public health and section 112(f) analysis occurs after a source category B. What is the affected source? it is appropriate to regulate U.S. EGUs has already complied with section 112(d) standards, An existing affected source under this whereas, potential delistings under section under CAA section 112. This 112(c)(9) may involve source categories unregulated final rule is the collection of coal- or oil- determination and the confirmatory by section 112. A delisting decision is significant fired EGUs in a subcategory within a assessments support our conclusion that in that the category that is delisted will no longer single contiguous area and under UARG’s delisting petition must be be subject to HAP regulation under the Act. It is common control. A new affected source difficult to justify why we would examine risks denied. from other sources under section 112(f), but not is each coal- or oil-fired EGU for which UARG attempts to dismiss the results under section 112(c)(9), where Congress established construction or reconstruction began of EPA’s national-scale Hg Risk TSD, such a specific test for delisting. after May 3, 2011.

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CAA section 112(a)(8) defines an EGU as: EGU as defined in CAA section HAP, with an alternate of SO2 as a a fossil fuel-fired combustion unit of more 112(a)(8) and, thus, potentially subject surrogate for acid gas HAP for coal-fired than 25 megawatts that serves a generator to this final rule. In addition, using the EGUs with FGD systems installed and that produces electricity for sale. A unit that construct of the definition of ‘‘oil-fired’’ operational; filterable PM as a surrogate cogenerates steam and electricity and from the ARP, we are finalizing in this supplies more than one-third of its potential for non-mercury HAP metals, with total electric output capacity and more than 25 rule a requirement that the unit fire coal non-mercury HAP metals and megawatts electrical output to any utility or oil (or natural gas), or any individual non-mercury HAP metals as power distribution system for sale shall be combination thereof, for more than 10.0 alternative equivalent standards; Hg; considered an electric utility steam percent of the average annual heat input and organic HAP. For oil-fired EGUs, generating unit. during any 3 consecutive calendar years this final rule regulates HCl and HF; or for more than 15.0 percent of the If an EGU burns coal (either as a filterable PM as a surrogate for total annual heat input during any one primary fuel or as a supplementary fuel) calendar year to be considered a ‘‘fossil HAP metals, with individual HAP or any combination of coal with another fuel-fired’’ EGU as defined in CAA metals as alternative equivalent fuel (except for solid waste as noted section 112(a)(8). However, if a new or standards; and organic HAP. below) where the coal accounts for more existing EGU is not coal- or oil-fired, than 10.0 percent of the average annual D. What emission limits and work and the unit burns natural gas heat input during any 3 consecutive practice standards must I meet and exclusively or burns natural gas in calendar years or for more than 15.0 what are the subcategories in the final combination with another fuel where percent of the annual heat input during rule? the natural gas constitutes 10 percent or any one calendar year after the more of the average annual heat input applicable compliance date, the unit is We are finalizing the emission during any 3 calendar years or 15 limitations presented in Tables 3 and 4 considered to be coal-fired under this percent or more of the annual heat input final rule. of this preamble. Within the two major during any 1 calendar year, the unit is subcategories of ‘‘coal’’ and ‘‘oil,’’ If a unit is not a coal-fired unit and considered to be natural gas-fired EGU burns only oil or burns oil in emission limitations were developed for and not subject to this final rule. As new and existing sources for seven combination with a fuel other than coal discussed later, we believe that this subcategories, two for coal-fired EGUs, (except solid waste as noted below) definition will address those situations one for IGCC EGUs burning synthetic where the oil accounts for more than where an EGU co-fires limited amounts 10.0 percent of the average annual heat of either coal or oil with natural gas or gas derived from coal- and/or solid oil- input during any 3 consecutive calendar other non-fossil fuels (e.g., biomass). derived fuel, one for solid oil-derived years or for more than 15.0 percent of If an EGU combusts solid waste, fuel-fired EGUs, and four for liquid oil- the annual heat input during any one standards issued pursuant to CAA fired EGUs, as described in more detail calendar year after the applicable section 129 apply to that EGU, rather below. The limited-use liquid oil-fired compliance date, the unit is considered than this final rule. subcategory, discussed elsewhere in this to be oil-fired under this final rule. preamble, is not presented in Table 3 C. What are the pollutants regulated by As noted below, the EPA is finalizing because only work practice standards this final rule? in this rule a definition to determine apply to this subcategory. whether the combustion unit is ‘‘fossil For coal-fired EGUs, this final rule fuel fired’’ such that it is considered an regulates HCl as a surrogate for acid gas

TABLE 3—EMISSION LIMITATIONS FOR COAL-FIRED AND SOLID OIL-DERIVED FUEL-FIRED EGUS

Filterable partic- Hydrogen Subcategory ulate matter chloride Mercury

Existing—Unit not low rank virgin coal ...... 3.0E–2 lb/ 2.0E–3 lb/ 1.2E0 lb/TBtu. MMBtu. MMBtu. (1.3E–2 lb/ (3.0E–1 lb/MWh) (2.0E–2 lb/MWh) GWh). Existing—Unit designed low rank virgin coal ...... 3.0E–2 lb/ 2.0E–3 lb/ 1.1E+1 lb/TBtu. MMBtu. MMBtu. (1.2E–1 lb/ (3.0E–1 lb/MWh) (2.0E–2 lb/MWh) GWh). 4.0E0 lb/TBtu a. (4.0E–2 lb/ GWh a). Existing—IGCC ...... 4.0E–2 lb/ 5.0E–4 lb/ 2.5E0 lb/TBtu. MMBtu. MMBtu. (3.0E–2 lb/ (4.0E–1 lb/MWh) (5.0E–3 lb/MWh) GWh). Existing—Solid oil-derived ...... 8.0E–3 lb/ 5.0E–3 lb/ 2.0E–1 lb/TBtu. MMBtu. MMBtu. (2.0E–3 lb/ (9.0E–2 lb/MWh) (8.0E–2 lb/MWh) GWh). New—Unit not low rank virgin coal ...... 7.0E–3 lb/MWh 4.0E–4 lb/MWh 2.0E–4 lb/GWh. New—Unit designed for low rank virgin coal ...... 7.0E–3 lb/MWh 4.0E–4 lb/MWh 4.0E–2 lb/GWh. New—IGCC ...... 7.0E–2 lb/MWh b 2.0E–3 lb/MWh d 3.0E–3 lb/ 9.0E–2 lb/MWh c GWh e. New—Solid oil-derived ...... 2.0E–2 lb/MWh 4.0E–4 lb/MWh 2.0E–3 lb/GWh. Note: lb/MMBtu = pounds pollutant per million British thermal units fuel input. lb/TBtu = pounds pollutant per trillion British thermal units fuel input. lb/MWh = pounds pollutant per megawatt-hour electric output (gross). lb/GWh = pounds pollutant per gigawatt-hour electric output (gross). a Beyond-the-floor limit as discussed elsewhere. b Duct burners on syngas; based on permit levels in comments received.

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c Duct burners on natural gas; based on permit levels in comments received. d Based on best-performing similar source. e Based on permit levels in comments received.

TABLE 4—EMISSION LIMITATIONS FOR LIQUID OIL-FIRED EGUS

Filterable particulate Hydrogen Hydrogen Subcategory matter chloride fluoride

Existing—Liquid oil—continental ...... 3.0E–2 lb/MMBtu ... 2.0E–3 lb/MMBtu ... 4.0E–4 lb/MMBtu. (3.0E–1 lb/MWh) .... (1.0E–2 lb/MWh) .... (4.0E–3 lb/MWh). Existing—Liquid oil—non-continental ...... 3.0E–2 lb/MMBtu ... 2.0E–4 lb/MMBtu ... 6.0E–5 lb/MMBtu. (3.0E–1 lb/MWh) .... (2.0E–3 lb/MWh) .... (5.0E–4 lb/MWh). New—Liquid oil—continental ...... 7.0E–2 lb/MWh ...... 4.0E–4 lb/MWh ...... 4.0E–4 lb/MWh. New—Liquid oil—non-continental ...... 2.0E–1 lb/MWh ...... 2.0E–3 lb/MWh ...... 5.0E–4 lb/MWh.

We are also finalizing alternate metals and total non-mercury metals final alternate emission limitations are equivalent emission standards (for (for filterable PM) from coal- and solid provided in Tables 5 and 6 of this certain subcategories) to the final oil-derived fuel-fired EGUs, and preamble. surrogate standards in three areas: SO2 individual and total metals (for (for HCl), individual non-mercury filterable PM) from oil-fired EGUs. The

TABLE 5—ALTERNATE EMISSION LIMITATIONS FOR EXISTING COAL- AND OIL-FIRED EGUS

Liquid oil, conti- Liquid oil, non-conti- Solid oil- Subcategory/Pollutant Coal-fired EGUs IGCC nental nental derived

SO2 ...... 2.0E–1 lb/MMBtu ... NA ...... NA ...... NA ...... 3.0E–1 lb/MMBtu. (1.5E0 lb/MWh) ...... (2.0E0 lb/MWh). Total non-mercury metals ...... 5.0E–5 lb/MMBtu ... 6.0E–5 lb/MMBtu ... 8.0E–4 lb/MMBtu ... 6.0E–4 lb/MMBtu ... 4.0E–5 lb/MMBtu. (5.0E–1 lb/GWh) .... (5.0E–1 lb/GWh) .... (8.0E–3 lb/MWh) a .. (7.0E–3 lb.MWh) a .. (6.0E–1 lb/GWh). Antimony, Sb ...... 8.0E–1 lb/TBtu ...... 1.4E0 lb/TBtu ...... 1.3E+1 lb/TBtu ...... 2.2E0 lb/TBtu ...... 8.0E–1 lb/TBtu. (8.0E–3 lb/GWh) .... (2.0E–2 lb/GWh) .... (2.0E–1 lb/GWh) .... (2.0E–2 lb/GWh) .... (8.0E–3 lb/GWh). Arsenic, As ...... 1.1E0 lb/TBtu ...... 1.5E0 lb/TBtu ...... 2.8E0 lb/TBtu ...... 4.3E0 lb/TBtu ...... 3.0E–1 lb/TBtu. (2.0E–2 lb/GWh) .... (2.0E–2 lb/GWh) .... (3.0E–2 lb/GWh) .... (8.0E–2 lb/GWh) .... (5.0E–3 lb/GWh). Beryllium, Be ...... 2.0E–1 lb/TBtu ...... 1.0E–1 lb/TBtu ...... 2.0E–1 lb/TBtu ...... 6.0E–1 lb/TBtu ...... 6.0E–2 lb/TBtu. (2.0E–3 lb/GWh) .... (1.0E–3 lb/GWh) .... (2.0E–3 lb/GWh) .... (3.0E–3 lb/GWh) .... (6.0E–4 lb/GWh). Cadmium, Cd ...... 3.0E–1 lb/TBtu ...... 1.5E–1 lb/TBtu ...... 3.0E–1 lb/TBtu ...... 3.0E–1 lb/TBtu ...... 3.0E–1 lb/TBtu. (3.0E–3 lb/GWh) .... (2.0E–3 lb/GWh) .... 2.0E–3 lb/GWh) ..... (3.0E–3 lb/GWh) .... (4.0E–3 lb/GWh). Chromium, Cr ...... 2.8E0 lb/TBtu ...... 2.9E0 lb/TBtu ...... 5.5E0 lb/TBtu ...... 3.1E+1 lb/TBtu ...... 8.0E–1 lb/TBtu. (3.0E–2 lb/GWh) .... (3.0E–2 lb/GWh) .... (6.0E–2 lb/GWh) .... (3.0E–1 lb/GWh) .... (2.0E–2 lb/GWh). Cobalt, Co ...... 8.0E–1 lb/TBtu ...... 1.2E0 lb/TBtu ...... 2.1E+1 lb/TBtu ...... 1.1E+2 lb/TBtu ...... 1.1E0 lb/TBtu. (8.0E–3 lb/GWh) .... (2.0E–2 lb/GWh) .... (3.0E–1 lb/GWh) .... (1.4E0 lb/GWh) ...... (2.0E–2 lb/GWh). Lead, Pb ...... 1.2E0 lb/TBtu ...... 1.9E+2 lb/MMBtu ... 8.1E0 lb/TBtu ...... 4.9E0 lb/TBtu ...... 8.0E–1 lb/TBtu. (2.0E–2 lb/GWh) .... (1.8E0 lb/MWh) ...... (8.0E–2 lb/GWh) .... (8.0E–2 lb/GWh) .... (2.0E–2 lb/GWh). Manganese, Mn ...... 4.0E0 lb/TBtu ...... 2.5E0 lb/TBtu ...... 2.2E+1 lb/TBtu ...... 2.0E+1 lb/TBtu ...... 2.3E0 lb/TBtu. (5.0E–2 lb/GWh ..... (3.0E–2 lb/GWh) .... (3.0E–1 lb/GWh) .... (3.0E–1 lb/GWh) .... (4.0E–2 lb/GWh). Mercury, Hg ...... NA ...... NA ...... 2.0E–1 lb/TBtu ...... 4.0E–2 lb/TBtu NA. (2.0E–3 lb/GWh) .... (4.0E–4 lb/GWh). Nickel, Ni ...... 3.5E0 lb/TBtu ...... 6.5E0 lb/TBtu ...... 1.1E+2 lb/TBtu ...... 4.7E+2 lb/TBtu ...... 9.0E0 lb/TBtu. (4.0E–2 lb/GWh) .... (7.0E–2 lb/GWh) .... (1.1E0 lb/GWh) ...... (4.1E0 lb/GWh) ...... (2.0E–1 lb/GWh). Selenium, Se ...... 5.0E0 lb/TBtu ...... 2.2E+1 lb/TBtu ...... 3.3E0 lb/TBtu ...... 9.8E0 lb/TBtu ...... 1.2E0 lb/TBtu. (6.0E–2 lb/GWh) .... (3.0E–1 lb/GWh) .... (4.0E–2 lb/GWh) .... (2.0E–1 lb/GWh) .... (2.0E–2 lb/GWh). NA = Not applicable. a Includes Hg.

TABLE 6—ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OIL-FIRED EGUS

Liquid oil, Liquid oil, Solid Subcategory/Pollutant Coal-fired EGUs IGCC a continental, non-continental, oil- lb/GWh lb/GWh derived

SO2 ...... 4.0E–1 lb/MWh ...... 4.0E–1 lb/MWh ...... NA ...... NA ...... 4.0E–1 lb/MWh Total non-mercury metals ...... 6.0E–2 lb/GWh ...... 4.0E–1 lb/GWh ...... 2.0E–4 lb/MWh b .... 7.0E–3 lb/MWh b .... 6.0E–1 lb/GWh Antimony, Sb ...... 8.0E–3 lb/GWh ...... 2.0E–2 lb/GWh ...... 1.0E–2 ...... 8.0E–3 ...... 8.0E–3 lb/GWh Arsenic, As ...... 3.0E–3 lb/GWh ...... 2.0E–2 lb/GWh ...... 3.0E–3 ...... 6.0E–2 ...... 3.0E–3 lb/GWh Beryllium, Be ...... 6.0E–4 lb/GWh ...... 1.0E–3 lb/GWh ...... 5.0E–4 ...... 2.0E–3 ...... 6.0E–4 lb/GWh Cadmium, Cd ...... 4.0E–4 lb/GWh ...... 2.0E–3 lb/GWh ...... 2.0E–4 ...... 2.0E–3 ...... 7.0E–4 lb/GWh Chromium, Cr ...... 7.0E–3 lb/GWh ...... 4.0E–2 lb/GWh ...... 2.0E–2 ...... 2.0E–2 ...... 6.0E–3 lb/GWh Cobalt, Co ...... 2.0E–3 lb/GWh ...... 4.0E–3 lb/GWh ...... 3.0E–2 ...... 3.0E–1 ...... 2.0E–3 lb/GWh Lead, Pb ...... 2.0E–3 lb/GWh ...... 9.0E–3 lb/GWh ...... 8.0E–3 ...... 3.0E–2 ...... 2.0E–2 lb/GWh Mercury, Hg ...... NA ...... NA ...... 1.0E–4 ...... 4.0E–4 ...... 2.0E–3 lb/GWh Manganese, Mn ...... 4.0E–3 lb/GWh ...... 2.0E–2 lb/GWh ...... 2.0E–2 ...... 1.0E–1 ...... 7.0E–3 lb/GWh

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TABLE 6—ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OIL-FIRED EGUS—Continued

Liquid oil, Liquid oil, Solid Subcategory/Pollutant Coal-fired EGUs IGCC a continental, non-continental, oil- lb/GWh lb/GWh derived

Nickel, Ni ...... 4.0E–2 lb/GWh ...... 7.0E–2 lb/GWh ...... 9.0E–2 ...... 4.1E0 ...... 4.0E–2 lb/GWh Selenium, Se ...... 6.0E–3 lb/GWh ...... 3.0E–1 lb/GWh ...... 2.0E–2 ...... 2.0E–2 ...... 6.0E–3 lb/GWh NA = Not applicable. a Based on best-performing similar source. b Includes Hg.

As noted elsewhere in this preamble, for organic HAP, including emissions of (1) meets the final definitions of ‘‘fossil we are finalizing a requirement to use dioxins and furans, for all subcategories fuel-fired’’ and ‘‘coal-fired electric filterable PM as a surrogate for the non- of EGUs. The work practice standard utility steam generating unit;’’ and (2) is mercury metallic HAP and HCl as a being finalized requires the not a coal-fired EGU in the ‘‘unit surrogate for the acid gas HAP for all implementation of periodic burner tune- designed for low rank virgin coal’’ subcategories of coal-fired EGUs and for up procedures described elsewhere in subcategory. the solid oil derived fuel-fired EGUs. this preamble. We are finalizing work We are finalizing that the EGU is For all liquid oil-fired EGUs, we are practice standards because the considered to be in the ‘‘unit designed finalizing a requirement to use filterable significant majority of data for measured for low rank virgin coal’’ subcategory if PM as a surrogate for the total metallic organic HAP emissions from EGUs are the EGU: (1) meets the final definitions HAP, and we are finalizing HCl and HF below the detection levels of the EPA of ‘‘fossil fuel-fired’’ and ‘‘coal-fired limits. test methods, even when long duration electric utility steam generating unit;’’ In addition, we are finalizing (around 8 hour) test runs are and (2) is designed to burn and is alternative standards for certain HAP for considered. As such, we consider it burning nonagglomerating virgin coal some subcategories. The alternative impracticable to measure emissions having a calorific value (moist, mineral pollutants and subcategories are as from these units. As discussed at matter-free basis) of less than 19,305 kJ/ follows: (1) SO2 as a surrogate to HCl for proposal, we believe the inaccuracy of kg (8,300 Btu/lb) and that is constructed all subcategories with add-on FGD a majority of measurements, coupled and operates at or near the mine that systems (except liquid oil-fired with the extended sampling times used, produces such coal.307 subcategories as there were no existing allow a work practice standard under We are finalizing that the EGU is units from which to base an alternate CAA section 112(h) to apply to these considered to be an IGCC unit if the SO2 limit); (2) individual non-mercury HAP.306 We believe that a work practice EGU: (1) Combusts a synthetic gas metallic HAP as an alternate to filterable standard will lead to a better derived from gasified coal or solid oil- PM for all subcategories (except that it environmental outcome than would be derived fuel (e.g., petroleum coke, pet includes Hg for liquid oil-fired obtained through a requirement to coke), (2) meets the final definition of subcategories); and (3) total non- measure a pollutant for which results ‘‘fossil fuel-fired,’’ and (3) is classified mercury metallic HAP as an alternate to may or may not be obtained. We believe as an IGCC unit. We are not filterable PM for all subcategories that the work practice standard will subcategorizing IGCC EGUs based on (except that it includes Hg for liquid oil- result in actions being taken that will the source of the syngas used (e.g., coal, fired subcategories). These alternative reduce emissions of these HAP. petroleum coke). Based on information standards are discussed elsewhere in In addition, as discussed below, we available to the Agency, although the this preamble. are creating a subcategory for limited fuel characteristics of coal and petcoke We are finalizing a beyond-the-floor use liquid oil-fired electric utility steam are quite different, the syngas products standard for Hg only for all existing generating unit with an annual capacity from both feedstocks have similar HAP coal-fired units designed for low rank factor of less than 8 percent of its content and similar HAP emissions virgin coal based on the use of activated maximum or nameplate heat input and characteristics that can be controlled in carbon injection (ACI) for Hg control, as we are establishing work practice a similar manner.308 described elsewhere in this preamble. standards applicable to such units We are finalizing that the EGU is The EPA has determined that this pursuant to CAA section 112(h). considered to be in the ‘‘Continental beyond-the-floor level is achievable We are finalizing that new or existing liquid oil-fired’’ subcategory if (1) meets after considering the relevant CAA EGUs are ‘‘coal-fired’’ if they combust the final definitions of ‘‘oil-fired electric section 112(d)(2) provisions. coal more than 10 percent of the average utility steam generating unit’’ and As noted elsewhere in this preamble, annual heat input during any 3 ‘‘fossil fuel-fired;’’ and (2) is located in we are also finalizing a compliance consecutive calendar years or for more the continental United States (U.S.). assurance option that would allow you than 15 percent of the annual heat input We are finalizing that the EGU is to monitor liquid oil fuel moisture to during any one calendar year and meet considered to be ‘‘Non-continental demonstrate that fuel moisture content the final definition of ‘‘fossil fuel-fired.’’ liquid oil-fired’’ subcategory if (1) meets is no greater than 1.0 percent. Provided We are finalizing that an EGU is the final definitions of ‘‘oil-fired electric that demonstration is made, you will considered to be in the coal-fired ‘‘unit utility steam generating unit’’ and not have to conduct additional testing designed for coal greater than or equal and monitoring to demonstrate to 8,300 Btu/lb’’ subcategory if the EGU: 307 ASTM Method D388–05, ‘‘Standard compliance with the HCl and HF Classification of Coals by Rank’’ (incorporated by emission limits for units in both liquid 306 We would also note that the EPA, as a part of reference, see § 63.14). oil subcategories (i.e., continental and the Industrial Boiler MACT reconsideration 308 U.S. Department of Energy, Wabash River Coal proposal that was signed on December 2, 2011, is Gaification Repowering Project. Project non-continental). proposing to establish work practice standards for Performance Summary; Clean Coal Technology Pursuant to CAA section 112(h), we control of dioxins and furans from industrial Demonstration Program. DOE/FE–0448. July 2002. are finalizing a work practice standard boilers. EPA–HQ–OAR–2009–0234–2933.

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‘‘fossil fuel-fired;’’ and (2) is located device that may most often will be used SO2 CEMS is used thereafter to outside continental U.S. is a PM continuous parameter demonstrate continuous compliance. If We are finalizing that the EGU is monitoring system (CPMS) in you instead opt to meet the HCl limit considered to be ‘‘solid oil-derived fuel- conjunction with an operating limit, as and use an HCl CEMS for compliance, fired’’ if (1) the EGU is not a coal-fired more fully described below.) For units you need not conduct an initial stack EGU and burns solid oil-derived fuel and pollutants not being monitored via test for HCl. Instead, the 30 boiler (e.g., petroleum coke, pet coke); and (2) CEMS, the owner or operator of an operating days of data collected with the meets the final definitions of ‘‘oil-fired affected unit must perform the initial certified HCl CEMS by the initial electric utility steam generating unit’’ performance testing in accordance with compliance demonstration date and ‘‘fossil fuel-fired.’’ established EPA reference test methods specified in § 63.10005 are used to We are finalizing that the EGU is or the voluntary consensus standard determine initial compliance. For units considered to be a ‘‘limited-use liquid methods incorporated by reference. not using the SO2 or HCl CEMS options, oil-fired’’ if (1) the EGU meets the final You, as the owner or operator of an you must conduct an initial stack test definitions of ‘‘oil-fired electric utility affected unit, must conduct the for HCl using EPA Method 26, 26A, or steam generating unit’’ and ‘‘fossil fuel- following compliance tests where 320 from Appendix A to part 60 of fired;’’ and (2) has an annual capacity applicable: chapter 40. You may use EPA Method factor of less than 8 percent of its (1) For coal-fired units, IGCC units, 26 or 320 or ASTM Method D6348–03 maximum or nameplate heat input, and solid oil-derived fuel-fired units, if (Reapproved 2010) with additional whichever is greater, averaged over a 24- you elect to comply with the filterable quality assurance if no entrained water month block contiguous period PM emission limit, you must conduct droplets exist in the exhaust gas, but commencing. filterable PM emissions testing using you must use Method 26A if entrained E. What are the requirements during EPA Method 5 from Appendix A to part water droplets exist in the exhaust gas. periods of startup, shutdown, and 60 of chapter 40 to determine initial (4) For liquid oil-fired units, you must malfunction? compliance. Alternatively, if you elect conduct initial performance testing as to comply with the total non-mercury follows. If you elect to meet the As discussed below in section VI.E., HAP metals emission limit or the filterable PM limit instead of the non- for startup and shutdown, the individual non-mercury HAP metals mercury metals limit (total or requirements have changed since emissions limits, you must conduct individual), then use Method 5 with the proposal. For periods of startup and HAP metals testing using EPA Method filter material maintained at 160° ± 14°C shutdown, the EPA is finalizing work 29 from Appendix A to part 60 of (320° ± 25°F). Alternatively, you may practice standards in lieu of numeric chapter 40. Note for this rule that the use a PM CEMS as discussed elsewhere emission limits. Numeric emission filter temperature for each Method 5 or in this preamble. If you elect to meet limits apply for all other periods for all 29 emissions test must be maintained at either the total or individual HAP pollutants, except organic HAP. For 160° ± 14 °C (320 ° ± 25 °F), and the metals limit, you will use Method 29 for malfunctions, the EPA is finalizing an material in Method 29 impingers must all non-mercury HAP metals. For Hg, affirmative defense for exceedances of be analyzed for metals content. conduct emissions testing using EPA the numerical emission limits that are Whenever metals testing is performed Method 29 or 30B from Appendix A to caused by malfunctions. with Method 29, you must report the part 60 of chapter 40, or ASTM Method F. What are the testing and initial front half and back half analytical D6784–02 (Reapproved 2008). For acid compliance requirements? fractions separately. gases, conduct HCl and HF testing using (2) For coal-fired, IGCC, and solid oil- EPA Method 26A, 320, or 26; or you We are requiring that you, as an derived fuel-fired units, you must use a may elect to comply by using an HCl owner or operator of a new or existing Hg CEMS or a sorbent trap monitoring CEMS and/or an HF CEMS; or under coal- or oil-fired EGU, must conduct system for both initial compliance and certain conditions you may choose to performance tests to demonstrate continuous compliance using the demonstrate compliance by measuring compliance with all applicable emission continuous Hg monitoring provisions of fuel moisture to demonstrate that limits. For units using certified Appendix A to 40 CFR part 63, subpart moisture content is no greater than 1.0 continuous emissions monitoring UUUUU, except where the low emitting percent. You must measure daily if fuel systems (CEMS) that directly measure EGU (LEE) requirements apply (see is delivered continuously or per the regulated pollutant under final 40 below). The initial performance test shipment if fuel is delivered on a batch CFR part 63, subpart UUUUU (e.g., Hg consists of all valid data recorded with basis, or you may use a fuel moisture CEMS, HCl CEMS, HF CEMS, SO2 the certified Hg monitoring system in content certification provided by your CEMS (where an SO2 limit applies as the 30 boiler operating days of data fuel supplier. If you use a CEMS, then the alternative equivalent standard)), or collected with the certified monitoring use the 30 boiler operating days of data sorbent trap monitoring systems, the system by the initial compliance collected with the certified monitoring initial performance test consists of all demonstration date specified in system by the initial compliance valid data recorded with the certified § 63.10005. demonstration date specified in monitoring system in the first 30 boiler (3) For coal-fired and solid oil-derived § 63.10005 to determine initial operating days of data collected with the fuel-fired units and new or compliance. certified monitoring system prior to the reconstructed IGCC units that employ (5) For the required performance stack initial compliance demonstration date FGD technology and elect to meet the tests, if you are demonstrating specified in § 63.10005. A source may alternative SO2 limit in place of the HCl compliance with a heat-input based also elect to use a PM CEMS to limit, you need not conduct an initial standard, you must conduct concurrent demonstrate compliance with the stack test for HCl or SO2. Instead, the 30 O2 or carbon dioxide (CO2) emission filterable PM emission limit. If this boiler operating days of data collected testing using EPA Method 3A or 3B option is selected, then the same with the certified SO2 CEMS by the from appendix A to part 60 of chapter provisions as noted above for other initial compliance demonstration date 40 or ANSI/ASME PTC 19.10–1981 and CEMS will apply. (Note that EPA specified in § 63.10005 are used to then use an appropriate equation, anticipates that the PM monitoring determine initial compliance, and the selected from among Equations 19–1

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through 19–9 in EPA Method 19 from output from the PM CPMS may be believes that the required work practice appendix A to part 60 of chapter 40, to expressed as milliamps, stack standards are appropriate and consistent convert measured pollutant concentration, or other raw data signal. with the requirement of CAA section concentrations to lb/MMBtu values. Meeting the operating limit serves as 112(h). Multiply the lb/MMBtu value by one your demonstration of continuous G. What are the continuous compliance million to get the lb/TBtu value (where compliance with the filterable PM, total requirements? applicable). If you choose to meet an non-mercury HAP metals, or individual electrical output-based emissions limit, non-mercury HAP metals limit. As To demonstrate continuous you must also collect concurrent stack mentioned earlier, if you use this compliance with the emission gas flow rate and electrical production method to demonstrate continuous limitations, the final rule includes the data. compliance, you must install a PM following requirements: (6) For an existing unit that you CPMS and establish the operating limit (1) Use of CEMS. Where a CEMS or a believe will qualify as LEE for Hg, you during the initial compliance test for sorbent trap monitoring system is used must conduct an initial Method 30B test filterable PM, total non-mercury HAP for demonstrating initial compliance, over 30 days and follow the calculation metals, or individual non-mercury HAP you also must use the CEMS or sorbent procedures in the final rule to document metals. As noted below, when you use trap monitoring system on a continuous a potential to emit less than 10 percent this operating limit, you can reduce basis to demonstrate ongoing of the applicable Hg emissions limit or stack testing frequency to demonstrate compliance with the numerical less than 29 pounds of Hg per year. If ongoing compliance. You may also opt emission limits. CEMS or sorbent trap your unit qualifies as a LEE for Hg, you to install and operate a PM CEMS monitoring system data are not used to must conduct subsequent performance certified in accordance with determine compliance with the work tests on an annual basis to demonstrate Performance Specification 11 and practice standards applicable during that the unit continues to qualify. For all Procedure 2 of 40 CFR part 60, periods of startup and shutdown, but other pollutants, you must conduct the Appendices B and F, respectively. If you sources that install a CEMS or a sorbent initial compliance test, and then all elect to use this option, then the trap monitoring system to demonstrate other required tests over a 3-year period, requirements for quarterly testing with compliance with the numerical and in all such tests, your emission Method 5, or annual testing and use of emission limits must operate the system results must be less than 50 percent of a PM CPMS, are no longer applicable. at all times, as EPA intends to evaluate the applicable emission limit. If you the continuous monitoring data from Dioxins/Furans and Non-Dioxin/Furan start-up and shutdown periods as qualify as a LEE on that basis, you must Organic HAP conduct subsequent performance tests discussed below. You must calculate a every 3 years to demonstrate that the For dioxins and furans and non- rolling average for each successive 30- unit continues to qualify. dioxin/furan organic HAP, you must boiler operating day rolling average (7) You may use results from tests submit documentation that you have period. All valid data collected during conducted no earlier than 12 months conducted a combustion process tune- each successive period will be used to before the compliance date of this rule up, a thorough equipment inspection, demonstrate compliance, except for data as the initial performance test for an and an optimization to minimize collected during periods of startup and applicable pollutant, provided that: generation of CO and NOX, all meeting shutdown; during those periods, the a. You certify and keep records the requirements of this final rule. The owner or operator must meet work demonstrating that no significant work practice standard involves practice requirements instead of the changes have occurred, maintaining and inspecting the burners numerical emission limits. There is no b. Tests were conducted using and associated combustion controls, numerical minimum data availability methods allowed in this rule in tuning the specific burner type to required to constitute a valid 30-boiler accordance with § 63.10007 and Table 5, optimize combustion, obtaining and operating day rolling average; however, c. You have records of all parameters recording CO and NOX values before you must monitor at all times that the needed to convert results to units of the and after burner adjustments, keeping process is in operation (including standard for the entire period, and records of activity and measurements, during startups and shutdowns, d. For a CEMS-based performance and submitting a report for each tune- although emissions during these periods test, you have all the required data for up conducted. You must collect CO and are not included in the 30-boiler the entire 30-boiler operating day rolling NOX data and may use portable operating day average). You must average period. analyzers (which include handheld or operate, maintain, and quality-assure similar devices) to monitor and verify the CEMS or sorbent trap monitoring Operating Limit for PM CEMS the results. The specific details are systems in accordance with the Under the final rule, you may elect to addressed in 40 CFR 63.10021 of the provisions in 40 CFR 63.10010 and comply continuously with an operating final rule. Appendix A and B of the final rule (for limit, established during the initial This same work practice standard also Hg, HCl, and HF CEMS), in accordance performance test, to demonstrate applies in place of any emission limits with Performance Specification 11 in continuous compliance with the for Hg, non-mercury metals HAP, acid Appendix B to 40 CFR part 60 and filterable PM, total non-mercury HAP gas HAP, dioxins and furans, and non- Procedure 2 in Appendix F to part 60 metals, or individual non-mercury HAP dioxin/furan organic HAP from a (for PM CEMS used for direct metals limit. You will use a PM CPMS limited-use, liquid oil-fired EGU (i.e., a compliance), or in accordance with 40 to monitor compliance with the unit that has an annual capacity factor CFR part 75 (for SO2 CEMS, and certain operating limit. The PM CPMS on oil of less than 8 percent of its ancillary monitors such as a diluent or operating principle must be based on in- maximum or nameplate heat input, moisture monitor). stack or extractive light scatter, light whichever is greater). The EPA For each unit using HCl, HF, SO2, PM, scintillation, beta attenuation, or mass established this subcategory in response or Hg CEMS or a sorbent trap accumulation detection of the exhaust to comments and a further analysis of monitoring system for continuous gas or representative exhaust gas the units within this subcategory in the compliance, you must install, certify, sample. The reportable measurement ICR database. For these units, EPA maintain, operate and quality-assure the

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additional CEMS (e.g., CEMS that checks (or 3-level system integrity PM (or HAP metals) and HCl and HF measure O2 or CO2 concentration, stack checks), and annual RATAs. Table A–2 from liquid oil-fired EGUs with the gas flow rate, and, if default moisture in Appendix A summarizes these following exceptions: values are not used, moisture content) ongoing QA test requirements and the a. If you use a PM CPMS and needed to convert pollutant applicable performance criteria for Hg associated operating limit, you may concentrations to units of the emission CEMS, which are consistent with those conduct the applicable Method 5 or standards or operating limits. Where published in support of CAMR and are, Method 29 test once annually rather appropriate, you must certify and thus, familiar to the industry. than quarterly, in which case you must quality-assure these additional CEMS For sorbent trap monitoring systems, re-establish the operating limit during according to 40 CFR part 75. a RATA is required for initial each performance test. A PM CPMS For HCl and HF CEMS, the EPA is certification, and annual RATAs are does not need to meet the requirements adding monitoring provisions as required for ongoing QA. The for a PM CEMS under PS 11. The final Appendix B to 40 CFR part 63, subpart performance specification for these rule includes basic quality checks that UUUUU. Appendix A references RATAs is the same as for the RATAs of the PM CPMS must meet and a performance specification (PS) 15 of the Hg CEMS. Bias adjustment of the requirement for you to develop and Appendix B to 40 CFR part 60 for measured Hg concentration data is not follow a site-specific monitoring plan to Fourier Transform Infrared (FTIR) required. For day-to-day operation of be approved by the delegated authority. CEMS for procedures to certify and the sorbent trap system, Appendix A You must demonstrate compliance with conduct ongoing quality assurance on requires you to follow the procedures the operating limit by using all valid these FTIR CEMS. In addition, we and QA/QC criteria in PS 12B in hourly data collected during each expect to publish a PS specific to HCl Appendix B to 40 CFR part 60. PS 12B successive 30-boiler operating day CEMS in the near future (prior to the is nearly identical to the Appendix K to period rolled daily. The 30-boiler compliance date of this rule). In the 40 CFR part 75, published in support of operating day rolling average is meantime, you may petition the CAMR and with which the industry is calculated by all of the valid hourly Administrator under the procedure familiar. The 40 CFR part 75 concepts average PM CPMS output values given in 40 CFR 63.7(f) for an alternative of: collected for the 30 boiler operating approach to compliance monitoring or a. Determining the due dates for days (excluding hours of startup and testing for HCl or any other regulated certain QA tests on the basis of ‘‘QA shutdown; see section V.E. of this pollutant. operating quarters’’ and preamble). When using a sorbent trap monitoring b. Grace periods for certain QA tests b. If you combust liquid fuels and if system, you may use each pair of apply to both Hg CEMS and sorbent trap your fuel moisture content is no greater sorbent traps to collect Hg samples for monitoring systems. Mercury than 1.0 percent, you may demonstrate no more than 15 boiler operating days. concentrations measured by Hg CEMS ongoing compliance with HCl and HF Under the general duty to monitor at all or sorbent trap systems are used emissions limits by: times, you must replace traps in a together with hourly flow rate, diluent i. Measuring fuel moisture content of timely manner to ensure that Hg gas, moisture, and electrical load data, each shipment of fuel if your fuel emissions are sampled continuously. to express the Hg emissions in units of arrives on a batch basis; For Hg monitoring, the EPA is adding the rule, on an hourly basis (i.e., lb/TBtu ii. Measuring fuel moisture content Hg monitoring provisions as Appendix or lb/GWh). Section 6 of Appendix A daily if your fuel arrives on a A to 40 CFR part 63, subpart UUUUU, provides the necessary equations for continuous basis; or and requiring use of these provisions to these unit conversions. iii. Obtaining and maintaining a fuel document continuous compliance with For HCl and HF CEMS, the EPA is moisture certification from your fuel the rule for coal-fired, IGCC, and solid adding monitoring provisions as supplier. oil derived-fired units that cannot Appendix B to 40 CFR part 63, Subpart Should the moisture in your liquid qualify as LEEs. Appendix A UUUUU. Appendix A references fuel be more than 1.0 percent, you must consolidates all Hg monitoring performance specification (PS) 15 of i. Conduct HCl and HF emissions provisions. Appendix B to 40 CFR part 60 for testing quarterly and establish site- Today’s rule provides two basic Hg Fourier Transform Infrared (FTIR) specific monitoring to demonstrate continuous monitoring options: Hg CEMS for procedures to certify and continued acid gas control performance CEMS and sorbent trap monitoring conduct ongoing quality assurance on between periodic tests, or systems. Appendix A requires initial these FTIR CEMS. In addition, we ii. Use an HCl CEMS and/or HF certification and periodic quality expect to promulgate a generic PS CEMS. assurance (QA) testing of the Hg CEMS specific to HCl CEMS prior to the c. If your existing unit qualifies as an and sorbent trap monitoring systems. compliance date of this rule. In the LEE for Hg, you must conduct another The certification tests required for the meantime, you may petition the 30-day Method 30B performance test on Hg CEMS are a 7-day calibration error Administrator under the procedure your unit once per year to reestablish test; a linearity check, using NIST- given in 40 CFR 63.7(f) for an alternative that the unit continues to qualify as a traceable elemental Hg standards; a 3- approach to compliance monitoring or LEE for Hg. If the results of the LEE test level system integrity check (similar to testing for HCl or any other regulated show that the unit exceeds 10 percent a linearity check), using NIST-traceable pollutant. of the emissions limit or exceeds the oxidized Hg standards; a cycle time test; (2) Use of stack tests. If you potential to emit 29 pounds of Hg per and a relative accuracy test audit demonstrate initial compliance on the year, you will lose LEE status for the (RATA). Table A–1 of Appendix A basis of a stack test, you must unit. You can regain LEE status for that summarizes the performance demonstrate continuous compliance by unit if every required performance test specifications for the required conducting periodic stack tests on a for a 3-year period shows that emissions certification tests. For ongoing QA of the quarterly basis. This includes filterable from the unit did not exceed the LEE Hg CEMS, Appendix A requires daily PM (or non-mercury HAP metals) and limit. If LEE status is lost for a solid fuel calibrations, weekly single-point system HCl from coal-fired and solid oil- unit, you must commence quarterly integrity checks, quarterly linearity derived fuel-fired EGUs, and filterable performance testing until you install,

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certify, and operate a Hg CEMS or a the source’s operations remain you must provide semiannual sorbent trap monitoring system, and you consistent with operating conditions compliance reports, as required by 40 must complete the installation and during a recent successful performance CFR 63.10(e)(3) of subpart A, that certification within 6 months of losing test. The requirement for a site-specific indicate whether a deviation from any LEE status; for a liquid fuel unit, you monitoring plan fills this gap and of the requirements in the rule occurred must commence quarterly performance ensures that in between tests, the source and whether or not any process changes testing. continues to operate in a manner occurred and compliance certifications d. If a liquid oil-fired EGU has an designed to maintain HCl and HF were reevaluated. As discussed below, annual capacity factor on oil of less than emissions in compliance with the we are finalizing a requirement to use 8 percent of its maximum or nameplate emission limits under this rule. The the 40 CFR part 75-based Emissions heat input, whichever is greater, you appropriate parameters to monitor will Collection and Monitoring Plan System must demonstrate continuous depend on the compliance strategy (ECMPS) for reporting emissions and compliance with the applicable work employed by a specific source, and thus related data for units using CEMS for practice standard by conducting at least EPA is enabling the monitoring most pollutants. Also, as discussed once every 36 calendar months (48 approach to be established on a case-by- below, for the PM CPMS, PM CEMS, calendar months if a neural network is case basis. Given the relatively small and performance test results, we require employed) a combustion process tune- number of these units and the other you to use EPA’s WebFIRE 309 database up, a thorough equipment inspection, compliance options available, we for reporting. and an optimization to minimize anticipate that this approach will apply This rule requires you to keep certain generation of CO and NOX, all meeting to a small set of units. The monitoring records to demonstrate compliance with the requirements of this final rule. You plan will identify the parameters each emission limit and work practice must maintain and inspect the burners monitored, the monitoring methods, the standard. The General Provisions to 40 and associated combustion controls, QA/QC elements that apply, and the CFR part 63 specify these recordkeeping tuning the specific burner type to data reduction elements (including requirements (see Table 9 to this optimize combustion, obtaining and appropriate averaging periods, as subpart). Among other specific records, recording CO and NOX values before applicable). See 40 CFR you must keep the following: and after burner adjustments, keeping 63.10000(c)(2)(ii). (1) All reports and notifications records of activity and measurements, (3) Work practice standard. For the submitted to comply with this rule. and submitting a report for each tune- performance tune-up work practice (2) Continuous monitoring data as up conducted. You must collect CO and requirements, you must demonstrate required in this rule. NOX data using portable analyzers continuous compliance by conducting (3) Each instance in which you did (which typically include handheld or the work practice at least once every 36 not meet an emission limit, work similar devices). Specific details are calendar months (48 calendar months if practice requirement, operating limit, or addressed in 40 CFR 63.10021 of the a neural network is employed). The other compliance obligation (i.e., final rule. In addition, you must record work practice involves maintaining and deviations from this rule). boiler operating hours, by fuel type, in inspecting the burners and associated (4) Daily hours of operation by each each calendar quarter. combustion controls, tuning the specific unit. e. The rule allows a grant of LEE burner type, as applicable, to optimize (5) As part of the general duty to keep status to existing units with test results combustion, obtaining and recording CO all monitoring data, fuel moisture content of liquid fuel, if you elect to that show a history of low, non-mercury and NOX values before and after burner emissions. As mentioned earlier, LEE adjustments, keeping records of activity demonstrate compliance using that status reduces testing frequency for and measurements, and submitting a information. units. After a 3-year period during report for each tune-up conducted. A (6) A copy of the results of all which every emissions test for a specific combustion tune-up will involve performance tests, monitor pollutant shows emissions no greater optimizing combustion of the unit certifications, performance evaluations, than 50 percent of the emissions limit, consistent with manufacturer’s or other compliance demonstrations you may reduce the emissions testing instruction as applicable, or in conducted to demonstrate initial or frequency for that specific non-mercury accordance with best combustion continuous compliance with this rule. (7) A copy of your site-specific pollutant to once every 36 months. If engineering practice for that burner performance evaluation test plans any subsequent emissions test for that type. pollutant exhibits emissions greater developed for this rule as specified in than 50 percent of the emissions limit, H. What are the notification, 40 CFR 63.8(e), if applicable. (8) A copy of your acid gas control you must revert to the original recordkeeping and reporting emissions testing frequency until you requirements? system parameter monitoring plan re-establish a 3-year period of very low All new and existing sources in all under 40 CFR 63.10000(c)(2)(ii). You also must submit the following emissions no greater than 50 percent of subcategories must comply with certain additional notifications: the standard. requirements of the General Provisions (1) Notifications required by the f. For liquid oil-fired units that (40 CFR part 63, subpart A), which are General Provisions. demonstrate continuous compliance identified in Table 9 of this final rule. (2) Initial Notification no later than with quarterly performance tests for HCl The General Provisions include specific 120 calendar days after you become and HF emission limits rather than requirements for notifications, subject to this subpart. through use of HCl and HF CEMS, the recordkeeping, and reporting. You must final rule requires a site-specific submit a notification of compliance 309 WebFIRE is the Internet version of FIRE. The monitoring plan in addition to the status report for each unit, according to Factor Information Retrieval (FIRE) Data System is quarterly tests. For these pollutants, the schedule required by 40 CFR 63.9(h) a database management system containing EPA’s there is unlikely to be any existing of the General Provisions, including a recommended emission estimation factors for criteria and HAP. It includes information about underlying monitoring (such as certification of compliance. industries and their emitting processes, the compliance assurance monitoring) that Except for units that use CEMS for chemicals emitted, and the emission factors serves as an additional tool to ensure continuous compliance, under this rule themselves.

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(3) Notification of Intent to conduct and the Compliance and Emissions Data reduce the burden on the regulated performance tests and/or compliance Reporting Interface (CEDRI) that is community by reducing the effort demonstration at least 60 calendar days accessed through EPA’s Central Data involved in data collection and before the performance test and/or Exchange (CDX), as described below. reporting activities. In the future, we compliance demonstration is scheduled. The data requirements for the anticipate there will be fewer and less (4) Notification of Compliance Status notification of compliance status and substantial data collection requests in 60 calendar days following completion compliance reports are described in conjunction with prospective required of the performance test and/or detail in the regulatory text (40 CFR residual risk assessments or technology compliance demonstration. 63.10031) of this rule, but they reviews. Electronic reporting will Electronic reporting is becoming a essentially mirror the requirements in substantially reduce this burden, common element of modern life (as 40 CFR 63.6 of the General Provisions. because the EPA will already have these evidenced by electronic banking and These reports will also be submitted to data available and consolidated in an income tax filing), and the EPA is WebFIRE using an electronic form electronic database named WebFIRE. beginning to require electronic found in CEDRI and through the CDX as We anticipate that using electronic submittal of environmental data. described below. As required in 40 CFR reporting for the required reports will Electronic reporting is already common 63.10031(f)(2) of the final rule, the result in an overall reduction in in environmental data collection and continuous monitoring summaries are reporting costs; for a discussion of the many media offices at EPA are reducing required to be submitted quarterly. The economic and cost impacts of electronic reporting burden for the regulated quarterly reports must include all of the reporting, see section XII.D. of this community by embracing electronic calculated 30-boiler operating day preamble. reporting systems as an alternative to rolling average values derived from the Another benefit of electronic data paper-based reporting. PM CPMS. These reports will also be submittal is that these data will greatly One of the major benefits of reporting submitted to WebFIRE using an improve the overall quality of existing electronically is standardization, to the electronic form found in CEDRI and and new emissions factors by extent possible, of the data reporting through the CDX, as described below. supplementing the pool of emissions formats that provides more certainty to This same approach will apply if a test data for establishing emissions users of what data are required in source elects to use a PM CEMS or factors and by ensuring that the factors specific reports. For example, electronic receives approval to use a HAP metals are more representative of current reporting software allows for more CEMS as an alternative monitoring industry operational procedures. A efficient data submittal and the method. common complaint heard from industry software’s validation mechanism helps and regulators is that emission factors industry users submit fewer incomplete The availability of electronic are outdated or not representative of a reports. This alone saves industry report reporting for sources subject to the particular source category. With timely processing resources and reduces Subpart UUUUU will provide receipt and incorporation of data from transaction times. Standardization also efficiency, improved services, better most performance tests, the EPA will be allows for development of efficient accessibility of information, and more able to ensure that emission factors, methods to compile and store much of transparency and accountability. when updated, represent the most the documentation required to be Additionally, submittal of these current range of operational practices. reported by this rule. required reports electronically provides Data entry of these electronic reports significant benefits for regulatory will be through the CEDRI that is Use of Electronic Reporting System agencies, industry, and the public. The accessed through EPA’s CDX We are requiring that you submit compliance data electronic reporting (www.epa.gov/cdx). Data submitted certain reports electronically. In system (CEDRI and CDX) is being electronically through CEDRI will be addition to supporting regulation developed such that once a facility’s stored in CDX as an official copy of development, control strategy initial data entry into the system is record. development, and other air pollution established and a report is generated, Once you have accessed CEDRI, you control activities, having an electronic subsequent data submittal will only will select the applicable subpart for the database populated with these reports consist of electronic updates to existing report that you are submitting. You will will save industry, state, local, tribal information in the system. Such a then select the report being submitted, agencies, the public, and the EPA system will effectively reduce the enter the data into the form, and click significant time, money, and effort burden associated with submittal of data on the submit button. In some cases, while also improving the transparency and reports by reducing the time, costs, such as with submittal of a notification and quality of emission inventories and, and effort required to submit and update of compliance status report, you will as a result, air quality regulations. hard copies of documentation. State, select the report icon, enter basic facility The reports to be submitted local, and tribal air pollution control information, and then upload the report electronically include all performance agencies will also benefit from having in a specified file format. test reports, notification of compliance access to the more streamlined and In addition, we believe that there will status reports, compliance, and accurate electronic data submitted to the be value in allowing other reporting continuous monitoring data summaries EPA. Electronic reporting will allow for forms to be developed and used in cases specified in 40 CFR 63.10031 of this an electronic review process rather than where the other reporting forms can rule. Performance tests are required to a manual data assessment, making provide an alternate electronic file be conducted as described in 40 CFR review and evaluation of the source- consistent with EPA’s form output 63.7 of the General Provisions. The data provided data and calculations easier format. This approach has been used that must be submitted as the and more efficient. Electronic reporting successfully to provide alternatives for performance test report are also will also benefit the public by other electronic forms (e.g., income tax described in 40 CFR 63.7. These data generating a more transparent review submittal). must be submitted (except in limited process and increasing the ease and In cases where performance test data cases) to EPA’s WebFIRE database by efficiency of data accessibility. are to be submitted to the EPA, you using the electronic reporting tool (ERT) Furthermore, electronic reporting will must enter the performance test data

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and information into the electronic CEMS, with the addition of a few codes monitor, or that quality-assured data reporting tool (ERT) which can be for the new parameters. were not obtained for the hour; and accessed at http://www.epa.gov/ttn/ The second type of data collected (4) The percent monitor availability chief/ert/index.html. In CEDRI, the user through ECMPS is certification and QA (PMA), which is updated hour-by-hour. must then upload the ERT file. CEDRI test data. These data include data from This generic record structure could submits a copy of the ERT project data linearity checks, RATAs, cycle time easily accommodate hourly average file directly to WebFIRE where the data tests, 7-day calibration error tests, and a measurements from CEMS used under are made available. Where performance number of other QA tests that are this rule. test reports are submitted, WebFIRE required to validate the emissions data. The ECMPS reporting structure is notifies the appropriate state, local, or You may submit the results of these quite flexible, which makes it useful for tribal agency contact that an ERT project tests to the EPA as soon as you obtain assessing compliance with various data file was received from the source. the results, with one notable exception. emission limits. The Derived Hourly Submitting performance test data Daily calibration error tests are not Value (DHV) record allows calculations electronically to the EPA will apply treated as individual QA tests, due to of a wide variety of quantities from the only to those performance tests the large number of records generated reported hourly emissions data. For conducted using test methods that will each quarter. Rather, these tests must be instance, if an emission limit is be supported by the ERT. The ERT included in the quarterly electronic expressed in units of lb/MMBtu, the contains a specific electronic data entry reports, along with the hourly emissions DHV record can be used to report hourly form for most of the commonly used data. The ECMPS system is set up to pollutant concentration values in these EPA reference methods. A listing of the receive and process certification and QA units of measure, since the lb/MMBtu pollutants and test methods supported data from SO2, CO2, O2, flow rate, and values can be derived from the hourly by the ERT is available at the ERT Web moisture monitoring systems that are pollutant and diluent gas (CO2 or O2) concentrations reported in the MHV site listed above. installed, certified, maintained, operated, and quality-assured according records. The ECMPS can also I. Submission of Emissions Test Results to 40 CFR part 75. EGUs routinely accommodate multiple DHV records for to the EPA submit these data to the EPA under the a given hour in which more than one derived value is required to be reported. The EPA has determined that ARP and other emissions trading The system will support reporting harmonization of the monitoring and programs. To accommodate the certification and hourly data in the units of the emission reporting requirements of this final rule QA tests for Hg CEMS, other CEMS, and standards (e.g., lb/MMBtu, lb/TBtu, lb/ with 40 CFR part 75 is appropriate, sorbent trap monitoring systems, the GWh, etc.) when hourly Hg where the affected industry already has structure and functionality of ECMPS concentration data are reported through a well-defined system for continuous needs relatively few changes, because ECMPS using the DHV record, in monitoring and reporting of emissions most of the tests are the same as those conjunction with the appropriate under that part. Therefore, the Agency required for other gas monitors. For equations and auxiliary information is finalizing monitoring and reporting reporting Hg, HCl, SO2, and HF CEMS such as heat input and electrical load requirements for most CEMS that are data under this rule, we are disabling (all of which are reported hourly in the consistent with 40 CFR part 75. You ECMPS’ 40 CFR part 75 bias test (which emissions reports). must report CEMS data (other than PM is required for certain types of monitors One change in this rule from standard CEMS data or data from alternative under the EPA’s SO2 and NOX 40 CFR part 75 emissions data reporting monitoring subject to site-specific emissions trading programs). The bias is elimination of the requirement to approval such as a HAP metals CEMS) adjustment of the data from these provide substitute data calculations to the EPA electronically, on a quarterly monitors is unnecessary for compliance within ECMPS. The ARP and other basis, using the ECMPS. with the rule. emissions trading programs that report The ECMPS process divides The third type of data collected emissions data to the EPA using 40 CFR electronic data into three categories, the through ECMPS is the hourly emissions part 75 require provision of a complete first of which is monitoring plan data. data, which, as previously noted, is data record. Emissions data are required You must maintain the electronic reported on a quarterly schedule. You to be reported for every unit operating monitoring plan separately and can must submit reports within 30 days after hour. When CEMS are out of service, update it at any time if necessary. The the end of each calendar quarter. The substitute data must be reported to fill monitoring plan documents the emissions data format requires hourly in the gaps. However, for the purposes characteristics of the affected units (e.g., reporting of all measured and calculated of compliance with a NESHAP, unit type, rated heat input capacity, etc.) emissions values, in a standardized reporting substitute data during monitor and the monitoring methodology used electronic format. You must report outages is not necessary, as for each parameter (e.g., CEMS). The direct measurements made with CEMS, quantification of total mass emissions is monitoring plan also describes the type such as gas concentrations, in a Monitor not the focus of the rule. Hours when a of monitoring equipment used Hourly Value (MHV) record. A typical monitoring system is out of service (hardware and software components), MHV record for gas concentration would be counted as hours of monitor includes analyzer span and range includes data fields for: down-time and may be a deviation from settings, and provides other useful (1) The parameter monitored (e.g., the monitoring requirements of this rule information. Nearly all coal-fired EGUs SO2); unless the rule provides an exception, are subject to the ARP and thus have (2) The unadjusted and bias-adjusted as it does for routine quality control and established electronic monitoring plans hourly concentration values (note that if maintenance activities. that describe their required SO2, flow bias adjustment is not required, only the In contrast to the CEMS-related data rate, CO2 or O2, and, in some cases, unadjusted hourly value is reported); that would be submitted through moisture monitoring systems. The EPA (3) The source of the data, i.e., a code ECMPS, you must submit reports of will adjust the ECMPS monitoring plan indicating either that each reported performance tests and PM CPMS data to format to accommodate this same type hourly concentration is a quality EPA’s WebFIRE database by using of information for Hg, HCl, and HF assured value from a primary or backup CEDRI that is accessed through EPA’s

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CDX (www.epa.gov/cdx). You must combination of coal with another fuel combust natural gas that exceeded the submit performance test data in the file (except solid waste as noted below), the 10 percent/15 percent thresholds set format generated through use of EPA’s unit is considered to be coal fired under forth in the proposed rule. In fact, in 40 ERT (see http://www.epa.gov/ttn/chief/ this proposed rule. If a unit is not a coal- CFR 63.9983 of the proposed rule, we ert/index.html) within 60 days of fired unit and burns only oil, or oil in stated that ‘‘[a]ny EGU that is not a coal- performance test completion. Electronic combination with another fuel other or oil-fired EGU and combusts natural data submittal requirements are than coal (except as noted below), the gas more than 10.0 percent of the described in section V.H. of this unit is considered to be oil fired under average annual heat input during the preamble. this proposed rule.’’ 76 FR 25020. previous 3 calendar years or for more Other notifications and reports not We proposed a definition for the term than 15.0 percent of the annual heat currently accepted by the electronic ‘‘fossil fuel-fired’’ because that term was input during any one of those calendar reporting system will be submitted in not defined in the statute and we years’’ is not subject to this subpart. hardcopy form at this time. wanted to clarify the level of fossil fuel We further explained that the combustion necessary to satisfy the percentages included in the definition VI. Summary of Significant Changes CAA section 112(a)(8) definition of of ‘‘fossil fuel-fired’’ would prevent Since Proposal EGU. The definition focused on coal units that primarily combusted fuels The previous section described the and oil combustion because the EPA other than fossil fuels from being requirements that EPA is finalizing in was only regulating coal- and oil-fired subjected to the final rule: this rule. This section will discuss in EGUs in this final rule. The proposed Units that do not meet the definition of greater detail the key changes EPA is definition contained two primary fossil-fuel fired would, in most cases, be making from the proposed. These elements: (1) the unit must be capable considered IB units subject to one of the changes result from EPA’s review of the of combusting sufficient amounts of coal Boiler NESHAP. Thus, for example, a additional data and information or oil to generate the equivalent of 25 biomass-fired EGU, regardless of size, that provided to us and our consideration of megawatts electrical output; and (2) the utilizes fossil fuels for startup and flame the many substantive and thoughtful unit must have fired coal or oil for more stabilization purposes only (i.e., less than or comments submitted on the proposal. than 10.0 percent of the average annual equal to 250 MMBtu/hr and used less than While our approach and methodology to heat input during the previous 3 10.0 percent of the average annual heat input establishing the standards remain the calendar years or for more than 15.0 during the previous 3 calendar years or less than 15.0 percent of the annual heat input same, the changes make the final rule percent of the annual heat input during during any one of those calendar years) is not more flexible and cost-effective, reduce any one of those calendar years. 76 FR considered to be a fossil fuel-fired EGU under reliability concerns and improve clarity, 25025. We further stated that for a unit this proposed rule. The EPA has based its while fully preserving, or improving, to be ‘‘capable of combusting’’ coal or threshold value on the definition of ‘‘oil- the public health and environmental oil the unit must have a permit that fired’’ in the ARP found at 40 CFR 72.2. As protection required by the CAA. authorized the combustion of coal or oil EPA has no data on such use for (e.g.) and also have the appropriate fuel biomass co-fired EGUs because their use has A. Applicability handling facilities on-site. Id. not yet become commonplace, we believe Since proposal, the EPA has made As explained in the proposed rule, this definition also accounts for the use of certain changes to the applicability natural gas-fired EGUs were not fossil fuels for flame stabilization use without included in the December 2000 listing inappropriately subjecting such units to this provisions of the final rule to provide proposed rule. Id. clarity. These changes do not change the so such units that otherwise met the universe of sources subject to the rule. CAA section 112(a)(8) definition of EGU Thus, in the proposed rule, we The EPA is revising a number of the because of natural gas combustion are intended to create thresholds to proposed definitions and adding a not subject to the final rule. In the determine when a unit is fossil fuel- definition for ‘‘natural gas-fired electric proposed rule, we stated that an EGU fired and for which fossil fuel the unit utility steam generating unit’’ in the that ‘‘combusts natural gas exclusively is fossil fuel-fired. We intended to final rule to provide clarity to the or natural gas in combination with include a unit combusting more than regulated community concerning the another fuel where the natural gas the defined amount of coal in one of the standards applicable to coal- and oil- constitutes 90 percent or more of the coal-fired EGU subcategories. If a unit is fired EGUs. average annual heat input during the not coal-fired and it is combusting more In the proposed rule, the EPA defined previous 3 calendar years or 85.0 than the defined amount of oil, we ‘‘[e]lectric utility steam generating unit’’ percent or more of the annual heat input intended to include the unit in one of consistent with the CAA section during any one of those calendar years’’ the oil-fired EGU subcategories. We also 112(a)(8) definition: was not subject to the rule. Id. The intended to make clear that EGUs that A fossil fuel-fired combustion unit of more references to 90 percent natural gas are neither coal-fired nor oil-fired but than 25 megawatts electric (MWe) that serves combustion over 3 years and 85 percent combust more than the defined amount a generator that produces electricity for sale. natural gas combustion in any one year of natural gas are natural gas-fired EGUs A fossil fuel-fired unit that cogenerates steam were included to align with the not subject to the final standards. and electricity and supplies more than one- definitions of ‘‘fossil fuel-fired’’ so that However, the definitions, as proposed, third of its potential electric output capacity it would be clear that units combusting were not sufficiently descriptive. and more than 25 MWe output to any utility primarily natural gas would not be For example, we included a definition power distribution system for sale is considered coal-fired, oil-fired, or IGCC for ‘‘coal-fired electric utility steam considered an electric utility steam EGUs if they burned 10 percent or less generating unit’’ that did not include the generating unit. of coal, oil, or synthetic gas derived requirement that the unit must combust 40 CFR 63.10042. from coal or solid oil over 3 years or 15 coal for at least 10 percent of the heat We also indicated how we would percent or less of such fuels in any one input over 3 years or 15 percent of the determine whether units were coal-fired year. We did not intend to suggest that heat input in any one year. Instead, in or oil-fired fired EGUs: ‘‘If an EGU burns to be considered a fossil fuel-fired EGU the proposed rule we indicated that a coal (either as a primary fuel or as a a natural gas-fired unit that is not a coal- unit was coal-fired if it burned coal in supplementary fuel), or any fired or oil-fired EGU would have to any amount. We did not intend to

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define a unit as coal-fired if it burned In addition to these changes, we are occurrence, at the end of the 6-month coal that accounted for 10 percent or revising the definition of ‘‘fossil fuel- period it would revert back to being less over 3 years or 15 percent of less fired’’ based on comments. We are subject to the Boiler NESHAP, or other in any one year, as that would be revising the definition to remove the applicable standard. We solicited inconsistent with the definition of fossil heat input equivalent of 25 MW because comment on the extent to which fuel-fired and the definitions for the oil- commenters noted that the equivalency situations like this might occur, how the fired EGU subcategories. Under the used (taken from 40 CFR part 60, EPA should address situations where proposed rule construct, a unit that subpart Da) could not be applied units change applicability, and whether combusts mostly biomass and less than consistently because of differing boiler we should include provisions similar to 10 percent coal over 3 years would not efficiencies. Commenters noted that those included in the final CISWI (40 be a coal-fired EGU because it would owners/operators were familiar with the CFR 60.2145) to address such situations. not meet the ‘‘fossil fuel-fired’’ use of the ‘‘MW’’ term for the boilers Id. definition. But a unit burning mostly and boilers include nameplate Several commenters asked the Agency petroleum coke and less than 10 percent capacities that are readily identifiable. to include provisions in the final rule coal over 3 years might be considered a We are also including a revision to the that would address situations like the coal-fired EGU because it would meet definition so that the fossil fuel ones described in the preamble to the the definition of ‘‘fossil fuel-fired’’ and combustion thresholds of 10 percent proposed rule. Because applicability to be burning some coal, even though that over 3 consecutive years and 15 percent the final rule is based in part on the level of coal combustion alone would in one year are evaluated after the statutory definition of an EGU is CAA not be sufficient to make the unit ‘‘fossil applicable compliance date of the final section 112(a)(8), similar to the situation fuel-fired’’ for coal. That result is at rule on a rolling basis. Commenters with units combusting solid waste odds with our intent. The same would correctly noted that some existing coal- under CAA section 129(g)(1) (e.g., hold true for an EGU that combusts and oil-fired EGUs will convert their CISWI Rule), we are adopting provisions mostly natural gas and less than 10 units to alternative fuels (e.g., natural in the final rule that are based on the percent synthetic gas derived from coal gas or biomass) and if the definition fuel switching provisions of the final over a 3-year period. Our proposal were finalized as proposed such units CISWI Rule (See Final CISWI Rule, 40 preamble makes clear that we did not could be improperly subjected to the CFR 60.2145). For example, a intend this result because we final standards. cogeneration unit that did not specifically stated that units burning 90 The new definition is set out in 40 historically provide more than one third percent or more natural gas over a 3- CFR 63.10042. of its potential electrical output capacity year period would be considered For clarity, we are also removing the to a power distribution system could natural-gas fired EGUs. 76 FR 25025. definition of ‘‘[u]nit designed to burn change its output and provide more In addition, we proposed to define liquid oil fuel subcategory,’’ revising the than 25 megawatts electrical output to ‘‘[u]nit designed to burn solid oil fuel definition of ‘‘[u]nit designed to burn any power distribution system for sale. subcategory’’ to include any EGU that solid oil fuel subcategory,’’ adding Such units would be subject to MATS. burned a solid fuel derived from oil for definitions for the continental and non- If the cogeneration unit later reduced its more than 10.0 percent of the average continental liquid oil-fired EGU output such that it no longer met the annual heat input during the previous 3 subcategories, and adding a definition of definition of an EGU, that source would calendar years or for more than 15.0 a limited-use liquid oil-fired EGU as set nevertheless remain subject to MATS percent of the annual heat input during out in 40 CFR 63.10042. for at least 6 months from the date that any one of those calendar years, either In the proposed rule, we stated that the unit first qualified as an EGU. alone or in combination with other we believed EGUs may at times not In addition, we are finalizing a fuels. We also included the 10 percent/ meet the definition of an EGU subject to provision whereby you may opt to 15 percent thresholds in the definition this subpart. For example, we explained remain subject to the provisions of this for the liquid oil subcategory, but, as that there may be some cogeneration final rule, unless you combust solid stated above, we did not include the units that are determined to be covered waste, in which case you are a solid thresholds in the definition of ‘‘coal- under the Boiler NESHAP. Such unit(s) waste incineration unit subject to standards under CAA section 129 (e.g., fired’’ EGU. Therefore, there would be may make a decision to increase the 40 CFR part 60, subpart CCCC (New some confusion for a source that proportion of production output being Source Performance Standards (NSPS) blended coal with solid oil derived fuel supplied to the electric utility grid, thus for Commercial and Industrial Solid (e.g., petroleum coke). For example, the causing the unit(s) to meet the EGU Waste Incineration Units), or subpart owner or operator of an EGU that cogeneration criteria (i.e., greater than DDDD (Emissions Guidelines (EG) for burned sufficient solid oil-derived fuel one-third of its potential output capacity Existing Commercial and Industrial that accounted for 80 percent of the heat and greater than 25 MW). In the input in a given year and the remainder Solid Waste Incineration Units)). We preamble to the proposed rule, we of the fuel was coal would not be sure believe the provision to opt to remain indicated that a unit subject to one of which standard applied because the subject to this final rule will ameliorate the Boiler NESHAP that increases its definitions in the proposed rule were conditions where EGUs may potentially electricity output and meets the internally inconsistent. move between NESHAP on a relatively For these reasons, we are revising the definition of an EGU would be subject frequent basis. Notwithstanding the definitions for ‘‘coal-fired electric utility to the EGU NESHAP for the 6-month provisions of this final rule, an EGU that period after the unit meets the EGU steam generating unit,’’ ‘‘integrated 310 starts combusting solid waste is subject gasification combined cycle electric definition. 76 FR 25026. Assuming to standards under CAA section 129, utility steam generating unit,’’ and ‘‘oil- the EGU did not meet the definition of and the unit remains subject to those fired electric utility steam generating an EGU following that initial standards until the unit no longer meets unit,’’ and we are adding a definition of the definition of a solid waste 310 Although we clearly stated the intent to ‘‘natural-gas fired electric utility steam require sources to comply for 6 months after incineration unit consistent with the generating unit’’ as set out in 40 CFR meeting the definition of an EGU, we inadvertently provisions of the applicable CAA 63.10042. failed to include the provision in the proposed rule. section 129 standards.

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The changes to the definitions There were no EGUs designed to burn a commenters indicating that the EPA described above provide clarity to nonagglomerating virgin coal having a should clarify in which subcategory a sources, permitting agencies, and the calorific value (moist, mineral matter-free unit belongs when it does not burn low public about the applicability of the rule basis) of 19,305 kJ/kg (8,300 Btu/lb) or less rank virgin coal but is designed to in an EGU with a height-to-depth ratio of and help ensure that sources are 3.82 or greater among the top performing 12 combust low rank virgin coal and has a appropriately covered by the regulation. percent of sources for Hg emissions, height-to-depth ratio of greater than B. Subcategories indicating a difference in the emissions for 3.82. Commenters also indicated that this HAP from these types of units. The CFB units that are burning coal- In this final rule, the EPA is adding boiler of a coal-fired EGU designed to burn refuse 311 or other nonagglomerating subcategories for limited-use oil-fired coal with that heat value is bigger than a virgin coal having a calorific value units and non-continental oil-fired units boiler designed to burn coals with higher (moist, mineral matter-free basis) of and revising the definitions for the coal- heat values to account for the larger volume of coal that must be combusted to generate 19,305 kJ/kg (8,300 Btu/lb) or greater are fired EGU subcategories. ‘‘designed to burn’’ any type of coal. The proposed rule subcategorized the desired level of electricity. Because the emissions of Hg are different between these Owners of CFB units that are not firing EGUs burning coal into two two subcategories, we are proposing to low rank virgin coal asked which subcategories: EGUs designed for coal ≥ establish different Hg emission limits for the subcategory they belong to based on 8,300 Btu/lb and EGUs designed for two coal-fired subcategories. For all other their ability to burn any type of coal virgin coal <8,300 Btu/lb (low rank HAP from these two subcategories of coal- (including low rank virgin coal) without virgin coal). We received a number of fired units, the data did not show any modification. These commenters also difference in the level of the HAP emissions comments indicating that the definition indicated that some coal refuse that is of the low rank virgin coal subcategory and, therefore, we have determined that it is not reasonable to establish separate combusted has a heating value less than was technically deficient. 8,300 Btu/lb but is not ‘‘virgin coal.’’ It Under CAA section 112(d)(1), the emissions limits for the other HAP. 76 FR was unclear to which subcategory they Administrator has the discretion to 25036–67. belonged since the proposed rule did ‘‘* * * distinguish among classes, Based on this determination, we types, and sizes of sources within a proposed to establish two subcategories not in fact require the unit to burn any category or subcategory in establishing with separate Hg limits. Comments on specific coal, instead only requiring the * * *’’ standards. The EPA maintains the proposed rule indicate that we unit be ‘‘designed’’ to burn lower Btu that, normally, any basis for correctly identified the EGUs that coal. Based on the comments received, we subcategorization (i.e., class, type, or should be included in each subcategory, reevaluated the subcategory definitions size) must be related to an effect on HAP but the comments also demonstrated because we were concerned that the emissions that is due to the difference that we made certain incorrect definitions we proposed would in class, type, or size of the units. See conclusions that require us to revise the 76 FR 25036–25037. The EPA believes definitions of our coal-fired EGU improperly categorize a number of the it is not reasonable to exercise our subcategories. The revised definitions EGUs in both subcategories. We discretion without such a difference ensure that the EGUs we identified at concluded that we should not maintain because if sources can achieve the same proposal as having different Hg the proposed definition for ‘‘[u]nits level of emissions reductions emissions remain in one subcategory. designed for coal <8,300 Btu/lb’’ and notwithstanding a difference in class, As stated above, we believed at exclude the CFB units and PC EGUs type, or size, the purposes of CAA proposal that the boiler size was the with a height-to-depth ratio less than section 112 are better served by cause of the different Hg emissions 3.82 that combusted low rank virgin requiring a similar level of control for characteristics that led us to propose coal. all such units in the category or subcategorization, but many We were equally concerned that the subcategory. See Lignite Energy Council commenters indicated that it was not subcategory definitions not be revised in v. EPA, 198 F. 3d 930, 933 (D.C. Cir. the boiler size but the fact that the EGUs a manner that would move EGUs that 1999) (‘‘EPA is not required by law to burned a nonagglomerating virgin coal we believed the data show could subcategorize—section 111[b][2] merely having a calorific value (moist, mineral comply with a more stringent standard states that ‘the Administrator may matter-free basis) of less than 19,305 kJ/ into a subcategory with a less stringent distinguish among classes, types, and kg (8,300 Btu/lb) (low rank virgin coal) standard because, aside from the type of sizes within categories of new sources’’’ that causes the disparity in Hg EGUs we identified, all other classes, (emphasis original)); see also CAA emissions. Several commenters types, and sizes of EGUs were represented among the top performing section 112(d)(1) (containing almost indicated that their EGUs were designed ≥ identical language to CAA section 111, to burn and burned low rank virgin coal 12 percent for Hg in the 8,300 Btu/lb CAA section 112(d)(1) provides that but the units did not meet the height-to- subcategory. We were particularly ‘‘the Administrator may distinguish depth ratio that EPA proposed. For concerned about the CFB units because among classes, types, and sizes of example, the height-to-depth ratio of other CFB units are well represented among the best performing EGUs for Hg sources within a category or subcategory certain EGUs in this subcategory is in ≥ in establishing [ ] standards * * *’’). fact 3.5, not 3.82. Further, there are in the 8,300 Btu/lb subcategory, but the Even if we determine that emissions other EGUs in this subcategory that are CFB units burning low rank virgin coal characteristics are different for units circulating fluidized bed (CFB) are not achieving the same levels of Hg that differ in class, type, or size, the combustion units which do not meet the emissions control. Including the best Agency may still decline to height-to-depth ratio parameters in the performing CFB units from the other subcategorize if there are compelling proposed rule, nor are they anything subcategory in the low rank virgin coal policy justifications that suggest like the pulverized coal (PC) EGUs we subcategory would likely lead to a Hg subcategorization is not appropriate. Id. initially identified as having the 3.82 standard as stringent as the standard for When developing the proposed rule, height-to-depth ratio. 311 It is our understanding that no unit combusts we examined the EGUs in the top In addition to the comments coal-refuse from nonagglomerating virgin coal performing 12 percent of sources for Hg concerning EGUs firing this coal, we having a calorific value (moist, mineral matter-free emissions. We determined that: received comments from at least two basis) of less than 19,305 kJ/kg (8,300 Btu/lb).

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EGUs in the ≥8,300 Btu/lb subcategory amounts of low rank virgin coal. For we would decline to exercise our because the CFB units from the other example, an EGU on the east coast (or discretion because the data demonstrate subcategory would be used to establish any other region) that was not designed that the best performing EGUs designed the floor. We believe that result would to burn and did not routinely burn low to burn and burning all other ranks of be inconsistent with the intent of the rank virgin coal could import one truck coal are able to achieve the MACT level proposed rule. We were also concerned full of low rank virgin coal and burn a of control using currently available about the information that some EGUs very small quantity of it periodically to controls and other HAP emission that fired low rank virgin coal had a meet the subcategory definition. To reduction mechanisms (e.g., coal height-to-depth ratio of 3.5, not 3.82, avoid creating this potential loophole, washing) for the ≥8,300 Btu/lb and that some EGUs that fired other we considered other characteristics that subcategory. ranks of coal had a height-to-depth ratio would distinguish EGUs combusting greater than 3.82. For these reasons, we low rank virgin coal. A second issue related to did not revise the definition to include We determined that these EGUs are subcategorization concerns non- CFB units and PC EGUs with a height- universally constructed ‘‘at or near’’ a continental liquid oil-fired EGUs. At to-depth ratio greater than 3.5. mine containing low rank virgin coal proposal, the EPA did not have After fully considering the available because it is not cost-effective to sufficient emissions data from non- information, including the comments transport large quantities of such fuel continental liquid oil-fired EGUs upon received, we have concluded that it is long distances. Furthermore, we believe which to base a subcategory and took appropriate to continue to base the that this subcategory of EGUs are almost comment on the issue. The data have subcategory definitions, at least in part, always built at a mine and limited since been provided in response to the on whether the EGUs were designed to transportation of the coal is only ICR and we received comments burn and, in fact, did burn low rank- required as the mine face moves over suggesting that a non-continental virgin coal, but that it is not appropriate the course of time. Many such EGUs subcategory is appropriate based on the to continue to use the height-to-depth construct dedicated rail lines, private location of such units, the limited ratio criteria because that approach roads, or conveyor systems to transport availability of alternative fuel sources, would potentially exclude EGUs we the coal to the EGU as the mine face and the fact that the emissions identified as having different Hg moves. We obtained information from characteristics of such units are distinct emission characteristics and include data acquired to develop the CSAPR from continental liquid oil-fired EGUs. EGUs that did not have different indicating that the longest distance any The EPA has evaluated the data and emissions characteristics. We recognize EGU firing low rank virgin coal comments and we agree that a that some commenters have taken the transports that coal is 40 miles. We subcategory is warranted based for the position that it is unlawful to believe that this distance is near the subcategorize based on factors such as outer limits for the transport of such reasons suggested by the commenters. fuel type but nothing in the statute coal, but, even for those EGUs, the EGUs Therefore, the Agency is finalizing the prohibits such an approach and the case were constructed closer to a now idle liquid oil-fired EGU subcategories of law supports this approach to the extent mine or closer to the working face of a ‘‘continental’’ and ‘‘non-continental.’’ courts have considered mine that has now expanded away from Lastly, the EPA did not have subcategorization based on such factors. the EGU site. For these reasons, we are sufficient information on limited-use See Sierra Club v. Costle, 657 F. 2d 298, including a requirement that the unit be liquid oil-fired EGUs upon which to 318–19 (D.C. Cir. 1981) (differing constructed and operated at or near a base a subcategory at proposal because pollutant content of input material can mine containing the low rank virgin some sources required to test under the justify a different standard based on coal it burns. ICR did not submit the data until after subcategorization authority to We are revising the coal-fired EGU proposal. We took comment on whether ‘‘distinguish among classes, types and subcategory definitions as set out in 40 a limited-use subcategory was sizes within categories of new sources’’). CFR 63.10042. warranted. Commenters indicated that Furthermore, we believe had Congress We believe the revised subcategory their units were a different class and intended to prohibit the EPA from definitions are reasonable for all the type of units because many of them reasons set forth above. The revised subcategorizing based on an EGU being were only called to service to address definitions maintain the EGUs we designed to use and using a certain reliability issues associated with, for identified as having different Hg material input (e.g., fuel) it would have example, natural gas curtailments. The clearly stated such intent in the CAA. emissions characteristics in one subcategory and the definitions prevent commenters further indicated that their However, we believe the Agency could units are different because of the decline to exercise its discretion to other EGUs that are not firing low rank generally infrequent use and the subcategorize even if the potential result virgin coal from being required to sporadic, and at times frequent, start-up would be the prohibition of the use of comply only with the less stringent Hg and shutdown periods (e.g., they are some materials if the circumstances emission standard. warranted. We note that even if we did As discussed in response to often only required to run for a couple not subcategorize on the final basis comments, we do not believe that of hours). These factors would lead to selected, the Hg emissions standard of additional subcategorization of other differences in the emissions 1.2E0 lb/Tbtu for the ‘‘unit designed for coal-fired EGUs is reasonable or characteristics for these units such that coal ≥8,300 Btu/lb’’ would remain the appropriate. All other coal-fired EGUs a numeric standard based on base load same. that are not designed to burn and are units would not likely be achievable We considered basing the subcategory burning low rank virgin coal are during the very limited times that these solely on an EGU being designed to represented among the best performing limited use oil-fired units operate. burn and burning low rank virgin coal. sources for Hg, such that no argument Based on comments received and our We decided not to do so because we exists to support that the Hg emissions own analysis, we are finalizing a were concerned that such a definition from those EGUs are different. In any subcategory for limited-use liquid oil- would allow sources to potentially meet case, even if emissions are somewhat fired EGUs as discussed further the definition by combusting very small different as some commenters suggest, elsewhere in this preamble.

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C. Emission Limits EGUs whose annual capacity factor is the case of units employing neural The proposed rule included less than 8 percent. network combustion controls, 54 months (48 months plus 180 days). If numerical emission limits for PM, Hg, D. Work Practice Standards for Organic the tune-up occurs prior to the HCl, HF, SO2, total HAP metals, and HAP Emissions individual HAP metals, depending on compliance date of the rule, you must As noted earlier in section V.D., the maintain adequate records to show that the subcategory and specific situation. final rule includes a work practice These proposed limits resulted from the tune-up met the requirements of this standard for organic HAP, including standard. calculations of MACT floors using dioxins and furans, applicable to all information and data available to the EGUs. As noted in section V.D. above, We have made a number of specific Agency prior to proposal, as required by the majority of emissions of these changes to address what to do for CAA section 112. Based on information pollutants are below the detection levels repairs that may require longer term and data received during the comment of EPA test methods and, therefore, are corrective actions, additional methods period, we have made data and impractical to measure. The work for evaluating combustion effectiveness, calculation corrections where necessary practice standard, described below, is a and clarification on procedures for and then re-ranked the best performing practical approach to ensuring that recording CO and NOX information. units in the MACT floor pools. Based on equipment is maintained and run so as There were specific comments that the new ranking, a limited number of to minimize emissions of dioxins and opposed the reference to manufacturer the emission limits in the final rule have furans, and we expect it to be more specifications, if available. We retained changed from those proposed. effective than establishing a numeric this language in the final rule, but note In addition to adjustments to the standard that cannot reliably be that these specifications apply only to emission limits themselves, we are measured or monitored. The work the extent applicable. Specifically, if finalizing several other changes to the practice also applies to the limited-use manufacturer specifications only emission standards that will simplify liquid oil-fired subcategory included in address equipment or conditions that and improve compliance for sources the final rule. are no longer present given current without compromising the toxics The work practice involves boiler operations, then those reductions achieved. One key change, as maintaining and inspecting the burners specifications are not applicable and discussed elsewhere in this notice, is and associated combustion controls (as other combustion engineering best that we have changed the surrogate for applicable), tuning the specific burner practice procedures for that burner type non-mercury metallic HAP from total type to optimize combustion, obtaining would apply. We have also clarified that particulate matter (PM) to filterable PM and recording CO and NOX values portable emission monitoring for coal-fired and solid oil-derived before and after the burner adjustments, equipment may be used to collect the EGUs. This change is based on keeping records of activity and required emissions optimization data information provided in comments and measurements, and submitting a report regarding pre- and post-tune-up CO and our own conclusion that measurement for each tune-up conducted. In Table 3 NOX emission levels. of filterable PM provided assurance of of the final regulation, we have clarified equivalent HAP emissions control. Most E. Requirements During Startup, that this refers to performance tune-ups, Shutdown, and Malfunction of the non-mercury metal HAP, for not tests, and have addressed the which PM is a surrogate, are filterable frequency requirement as discussed in We proposed numerical emission PM and the one that is not (Se) is well response to comments about the standards that would apply at all times, controlled by the limit on acid gases. appropriateness of the 18-month including during periods of startup, Using filterable PM as the surrogate will frequency. The provisions of 40 CFR shutdown, and malfunction. Although allow us to use continuous PM 63.10006(h)(i) refer to 40 CFR at proposal we stated that we were not monitoring systems, which measure 63.10021(e) for the specific steps setting a different standard for startup filterable (but not total) PM, thereby required to be part of the periodic tune- and shutdown, we did propose different providing a more continuous measure of up. We have also adjusted the language standards for startup and shutdown by compliance. in the final rule to recognize the value our inclusion of the default values For liquid oil-fired EGUs, based on of automated boiler optimization tools described below, which applied only comments received and corrections such as neural network systems. during startup and shutdown. made to the data submitted, we have Under the final rule, the tune-up must Specifically, we stated: added a filterable PM limit in the final be conducted at each planned major rule as an alternative equivalent outage and in no event less frequently To appropriately determine emissions standard for the total metal-HAP limit in than every 36 calendar months, with an during startup and shutdown and account for those emissions in assessing compliance with the proposed rule. In addition, as exception that if the unit employs a the proposed emission standards, we propose discussed elsewhere in this notice, we neural-network system for combustion use of a default diluent value of 10.0 percent have added measurement of the optimization during hours of normal O2 or the corresponding fuel specific CO2 moisture content of the oil (with a 1 unit operation, the required frequency is concentration for calculating emissions in percent limit) as an alternate a minimum of once every 4 years (48 units of lb/MMBtu or lb/TBtu during startup compliance assurance measure for calendar months). Initial compliance or shutdown periods. For calculating liquid oil-fired EGUs for determining with the work practice standard of emissions in units of lb/MWh or lb/GWh, we compliance with the HCl and HF limits. maintaining burners must occur within propose source owners use an electrical Direct measurement of HCl and HF 180 days of the compliance date of the production rate of 5 percent of rated capacity remains a compliance demonstration rule. The initial compliance during periods of startup or shutdown. We method in the final rule. Finally, as demonstration for the work practice recognize that there are other approaches for determining emissions during periods of discussed in section VI.D of this notice, standard of conducting a tune-up may startup and shutdown, and we request the final work practice standard occur prior to the compliance date of comment on those approaches. We further consisting of burner tune-ups, much like the rule, but must occur no later than 42 solicit comment on the proposed approach those required for organic HAP control, months (36 months plus 180 days) from described above and whether the values we for those limited-use liquid oil-fired the compliance date of the rule or, in are proposing are appropriate.

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We proposed application of the sufficient data on emissions that occur As for the work practices, in this final respective emission limits during during startup and shutdown on which rule, the EPA is requiring sources to periods of startup and shutdown and to set emission standards. We are operate using either natural gas or use of default values to calculate the therefore establishing work practice distillate oil for ignition during startup. emission limits. The standards that standards rather than numeric The EPA also is requiring sources to apply at all times other than startup and emissions standards for periods of vent emissions to the main stack(s) and shutdown are production-based limits, startup and shutdown in the final rule. operate all control devices necessary to which is why we proposed the default Before we describe those work practices, meet the normal operating standards values. The default values were meant we first address what constitutes startup under this final rule (with the exception to account for the fact that during and shutdown. of dry scrubbers and SCRs) when coal, startup and shutdown events, Several commenters had an expansive solid oil-derived fuel, or residual oil is production (in this case the generation view of what constitutes startup and fired in the boiler during startup or of electricity) is by definition shutdown. We disagree with these shutdown. It is the responsibility of the nonexistent. Thus, in effect, we commenters that asserted that periods of operators of EGUs to start their dry proposed a separate standard to apply ‘‘load swings’’ should be considered scrubber and SCR systems appropriately during startup and shutdown. ‘‘startup’’ or ‘‘shutdown,’’ as they are to comply with relevant standards We received a variety of comments on generally routine, normal operations applicable during normal operation. the proposed standards that would with production (i.e., generation of The EPA carefully considered fuels apply during startup and shutdown. electricity) taking place. We maintain and potential operational constraints of Many commenters pointed to the lack of that the standards as promulgated air pollution control devices (APCDs) data in the record concerning emissions account for any variability in emissions when designing its work practices for that occur during periods of startup and that may occur during these periods periods of startup and shutdown. The shutdown. They further asserted that over a 30-day averaging period, and EPA notes that there is no technical emissions during these periods can be commenters have provided no data that barrier to burning natural gas or highly variable in light of the sequence cause us to doubt that determination. distillate oil for longer portions of of events that occurs during the startup We have included definitions of startup startup or shutdown periods, if needed, and shutdown of an EGU. Although a and shutdown in the final rule that are at a boiler, and the HAP emission number of commenters supported the consistent with the definitions in the reduction benefits warrant additional use of the diluent factor approach, proposed rule. At proposal, we defined utilization of such fuels until the including the default 5 percent of rated startup as the setting in operation of an temperature and stack emissions capacity, during startup/shutdown affected source or portion of an affected pressure is sufficient to engage the periods, other commenters questioned source for any purpose, and shutdown APCDs. The EPA is aware that SCR the feasibility of collecting additional as the cessation of operation of an systems with ammonia injection need to data during such periods and had affected source or portion of an affected be operated within a prescribed and concerns regarding the reliability of source for any purpose. relatively narrow temperature window measurements obtained from EGUs Commenters sought more clarity to provide NOX reductions. Further, the during such periods. regarding the meaning of these terms as EPA is aware that dry scrubbers also In response to the Agency’s ICR to the applied to EGUs, so we are revising the need to be operated close to flue gas utility industry, seven owners or definitions in the final rule as set out in saturation temperature. Because these operators indicated that they provided 40 CFR 63.10042. devices have specific temperature startup and shutdown data for their These interpretations are tailored for requirements for proper operation, the EGUs. These data were submitted in EGUs and are consistent with the EPA notes in its work practices that it response to the requirement in the ICR definitions of ‘‘startup’’ and is the responsibility of the operators of to provide all available data from the 5 ‘‘shutdown’’ contained in the 40 CFR EGUs to start their SCR and dry years prior to the date the ICR was part 63, subpart A General Provisions. scrubber systems appropriately to issued. Of these data, there were almost We believe these revised definitions comply with relevant standards no HAP data for startup and shutdown address the comments and are rational applicable during normal operation. periods and almost all of the data failed based on the fact that EGUs function to Some commenters have asserted that to meet our data quality provide electricity primarily for sale to firing of fuel oil during periods of requirements.312 Thus, we do not have the grid but also at times for use on-site; startup and shutdown constrains therefore, EGUs should be considered to operation of PM controls (ESPs and 312 In response to the ICR, we also received SO2 be operating normally at all times baghouses) because under cooler CEMS data and the Agency had additional SO2 electricity is generated. We further conditions, acids and tars can condense CEMS data available through the CAMD ARP believe these revised definitions address on surfaces in these controls. The database. We are not able to identify specific periods of start-up and shutdown in either the ICR what some commenters describe as commenters assert that such CEMS data or the CAMD ARP data, and the ICR ‘‘warm’’ and ‘‘hot’’ startups as long as condensation can cause detrimental respondents do not indicate that the ICR data the EGU is shutdown (i.e., no fuel fired impacts on hardware and operation of includes periods of startup and shutdown. We set and no electricity generation) prior to these controls, and could cause safety the emission limits for SO2 and HCl using the data provided to the EPA from the 2010 ICR, not the the ‘‘warm’’ or ‘‘hot’’ startup period. concerns. The EPA understands that CAMD data, since those data were taken concerns with acidic and tarry deposits concurrently under the same specified operating establish an SO2 standard during periods of startup are related to firing of heavy (residual) conditions using the same fuel. We used the SO2 and shutdown and the numeric standards do not oil and not distillate oil. Accordingly, CEMS data that was submitted in response to the apply to those periods in the final rule. In contrast, with residual fuel oil firing, site-specific ICR by converting it to single point data to correlate the NSPS for SO2 is applicable during periods of to the data from units that did not provide CEMS startup and shutdown since the long term CAMD flue gas temperature and oxygen (O2) data from the relevant testing period. The emissions ARP CEMS data were used to determine the average concentration thresholds may be limits for the NESHAP incorporated variability by performance of the best demonstrated technology. applicable to minimize condensation of applying the 99 percent UPL to the average Those long term data were assumed to incorporate emissions developed from the stack test data and process variability including that associated with acids and tars and thereby minimize any SO2 CEMS data that was converted to stack test fuel and process/operational changes and periods of potential for detrimental impacts on data. Thus, we did not have data on which to startup and shutdown. hardware and any safety concerns.

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However, the EPA notes that its work under this final rule will provide the and duration of various malfunctions practice requirements provide flexibility EPA with information to more fully that might occur. As such, the to the operator to take appropriate site- analyze this issue and address it during performance of units that are specific remedial measures, if needed. the 8-year review established under malfunctioning is not ‘‘reasonably’’ The EPA further notes that boilers have CAA section 112. foreseeable. See, e.g., Sierra Club v. several options to prevent detrimental We now address malfunctions. In EPA, 167 F. 3d 658, 662 (D.C. Cir. 1999) impacts by: (1) Using startup fuels, contrast to the exclusion of startup and (The EPA typically has wide latitude in natural gas or distillate oil, until shutdown period emissions from 30- determining the extent of data-gathering appropriate flue gas conditions have boiler operating day rolling average necessary to solve a problem. We been reached and then fire residual oil; emissions, the final rule requires generally defer to an agency’s decision (2) pre-coating the PM control inclusion of emissions during periods of to proceed on the basis of imperfect surfaces 313 with an alkaline powder source or APCD malfunction. We have scientific information, rather than to (e.g., limestone); (3) installing concluded that when combined with the ‘‘invest the resources to conduct the chemically resistant bags 314 in availability of an affirmative defense as perfect study.’’). See also, Weyerhaeuser baghouses if applicable; and (4) using described below, this is an appropriate v. Costle, 590 F.2d 1011, 1058 (D.C. Cir. low-sulfur oils. The EPA also notes that and practical approach. 1978) (‘‘In the nature of things, no currently the industry has many As mentioned earlier, periods of general limit, individual permit, or even operational residual oil-fired boilers that startup, normal operations, and any upset provision can anticipate all are started up with either natural gas or shutdown are all predictable and upset situations. After a certain point, distillate fuel oil. At these boilers, the routine aspects of a source’s operations. the transgression of regulatory limits transition from the startup fuel, However, by contrast, malfunction is caused by ‘uncontrollable acts of third distillate oil or natural gas, to residual defined as a ‘‘sudden, infrequent, and parties,’ such as strikes, sabotage, oil is already being practiced without not reasonably preventable failure of air operator intoxication or insanity, and a unacceptable impacts on APCDs pollution control and monitoring variety of other eventualities, must be a including PM controls, which are equipment, process equipment or a matter for the administrative exercise of operated to meet applicable opacity process to operate in a normal or usual case-by-case enforcement discretion, not limits. Based on this experience and the manner * * *’’ (40 CFR 63.2). The EPA for specification in advance by options described above, those boilers has determined that CAA section 112 regulation.’’). In addition, the goal of a where residual oil is used for either a does not require that emissions that best controlled or best performing part of the startup period, or as the main occur during periods of malfunction be source is to operate in such a way as to fuel, will also be able to operate their factored into development of CAA avoid malfunctions of the source and PM controls to meet the work practice section 112 standards. Under CAA accounting for malfunctions could lead section 112, emissions standards for requirements of the rule. Note that coal to standards that are significantly less new sources must be no less stringent firing is done at high enough stringent than levels that are achieved than the level ‘‘achieved’’ by the best temperatures that concerns with by a well-performing non- controlled similar source and for condensation are not relevant. None of malfunctioning source. The EPA’s existing sources generally must be no the commenters have specifically approach to malfunctions is consistent less stringent than the average emission commented on this aspect of coal firing. with CAA section 112, and we believe limitation ‘‘achieved’’ by the best The EPA is not aware of any it is a reasonable interpretation of the operational constraints applicable to performing 12 percent of sources in the statute. This approach to malfunctions operation of wet scrubbers during category. There is nothing in CAA has been used consistently in CAA startup that could cause detrimental section 112 that directs the Agency to section 112 and CAA section 129 impacts on wet scrubber hardware and consider malfunctions in determining rulemaking actions since the D.C. safety concerns and none of the the level ‘‘achieved’’ by the best Circuit’s decision in Sierra Club v. EPA, commenters have commented on this performing or best controlled sources 551 F.3d 1019 (D.C. Cir. 2008) vacated aspect of wet scrubber operation. when setting emission standards. Finally, the EPA notes that dry Moreover, while the EPA accounts for the SSM exemption contained in CFR sorbent injection (DSI) can be applied variability in setting emissions 63.6(f)(1) and 40 CFR 63.6(h)(1). (See, across a very broad temperature range standards consistent with the CAA e.g., National Emission Standards for and will be engaged when residual oil section 112 case law, nothing in that Hazardous Air Pollutants From the or coal is fired in a boiler to comply case law requires the Agency to Portland Cement Manufacturing with HCl requirements. Again, no consider malfunctions as part of that Industry and Standards of Performance comments have been received on this analysis. Clean Air Act section 112 uses for Portland Cement Plants, 75 FR 54970 aspect of DSI operation. the concept of ‘‘best controlled’’ and (September 9, 2010); Standards of This final rule requires work practice ‘‘best performing’’ unit in defining the Performance for New Stationary Sources standards for emissions during startup level of stringency that CAA section 112 and Emission Guidelines for Existing and shutdown, and the rule requires performance standards must meet. Sources: Sewage Sludge Incineration sources to measure and report their Applying the concept of ‘‘best Units; Final Rule, 76 FR 15372 (March emissions at all times, including periods controlled’’ or ‘‘best performing’’ to a 21, 2011). of startup and shutdown, when unit that is malfunctioning presents In the event that a source fails to continuous monitoring is used to significant difficulties, as malfunctions comply with the applicable CAA section demonstrate compliance. Data collected are sudden and unexpected events. 112(d) standards as a result of a Further, accounting for malfunctions malfunction event, the EPA would 313 Coal Power, May 1, 2007: http:// would be difficult, if not impossible, determine an appropriate response www.coalpowermag.com/plant_design/Coal-Plant- given the myriad different types of based on, among other things, the good O-and-M-River-Locks-and-Barges-Are-an-Aging- malfunctions that can occur across all faith efforts of the source to minimize Workforce-Too 36.html. emissions during malfunction periods, 314 Neundorfer: Lesson #r, p.4–7, Table 4–1: sources in the category and given the http://www.neundorfer.com/FileUploads/CMSFiles/ difficulties associated with predicting or including preventative and corrective Fabric%20Filter%2OMaterial [0].pdf. accounting for the frequency, degree, actions, as well as root cause analyses

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to ascertain and rectify excess possible when the applicable emission civil penalties for excess emissions that emissions. The EPA would also limitations were being exceeded * * *’’ are proven to be beyond the control of consider whether the source’s failure to and that ‘‘[a]ll possible steps were taken the source. By incorporating an comply with the CAA section 112(d) to minimize the impact of the excess affirmative defense, the EPA has standard was, in fact, ‘‘sudden, emissions on ambient air quality, the formalized its approach to upset events. infrequent, not reasonably preventable’’ environment and human health * * *’’ In a Clean Water Act setting, the Ninth and was not instead ‘‘caused in part by In any judicial or administrative Circuit required this type of formalized poor maintenance or careless proceeding, the Administrator may approach when regulating ‘‘upsets operation.’’ 40 CFR 63.2 (definition of challenge the assertion of the affirmative beyond the control of the permit malfunction). defense and, if the respondent has not holder.’’ Marathon Oil Co. v. EPA, 564 Finally, the EPA recognizes that even met its burden of proving all of the F.2d 1253, 1272–73 (9th Cir. 1977). But equipment that is properly designed and requirements in the affirmative defense, see, Weyerhaeuser Co. v. Costle, 590 maintained can sometimes fail and that appropriate penalties may be assessed F.2d 1011, 1057–58 (D.C. Cir. 1978) such failure can sometimes cause an in accordance with CAA section 113 (holding that an informal approach is exceedance of the relevant emission (see also 40 CFR 22.27). adequate). The affirmative defense standard. (See, e.g., State The EPA is including an affirmative provisions give the EPA the flexibility to Implementation Plans: Policy Regarding defense in the final rule as we have in ensure both that its emission limitations Excessive Emissions During other recent MACT rules so as to are ‘‘continuous’’ as required by 42 Malfunctions, Startup, and Shutdown balance the tension, inherent in many U.S.C. 7602(k), and account for (Sept. 20, 1999); Policy on Excess types of air regulation, to ensure unplanned upsets and thus support the Emissions During Startup, Shutdown, adequate compliance while reasonableness of the standard as a Maintenance, and Malfunctions (Feb. simultaneously recognizing that despite whole. 15, 1983)). The EPA is therefore adding the most diligent of efforts, emission F. Testing and Initial Compliance to the final rule an affirmative defense limits may be exceeded under We have carefully evaluated the wide- to civil penalties for exceedances of circumstances beyond the control of the ranging comments on testing, emission limits that are caused by source. The EPA must establish continuous monitoring, and other malfunctions. See 40 CFR 63.10042 emission standards that ‘‘limit the provisions regarding initial compliance (defining ‘‘affirmative defense’’ to mean, quantity, rate, or concentration of demonstrations, and we have made in the context of an enforcement emissions of air pollutants on a adjustments intended to help streamline proceeding, a response or defense put continuous basis.’’ 42 U.S.C. 7602(k) implementation while still ensuring forward by a defendant, regarding (defining ‘‘emission limitation and adequate demonstration of compliance which the defendant has the burden of emission standard’’). See generally with the emission limits and other proof, and the merits of which are Sierra Club v. EPA, 551 F.3d 1019, 1021 standards established under this final independently and objectively (D.C. Cir. 2008). Thus, the EPA is rule. The significant changes include: evaluated in a judicial or administrative required to ensure that section 112 proceeding). We also have added other emissions limitations are continuous. 1. No Fuel Analysis Requirements regulatory provisions to specify the The affirmative defense for malfunction Apart from an alternative that allows elements that are necessary to establish events meets this requirement by you to analyze fuel moisture for liquid this affirmative defense; the source must ensuring that even where there is a oil-fired EGUs rather than measuring prove by a preponderance of the malfunction, the emission limitation is HCl and HF, the final rule does not evidence that it has met all of the still enforceable through injunctive include any of the fuel analysis elements set forth in 63.10001. (See 40 relief. While ‘‘continuous’’ limitations, requirements that were in the proposed CFR 22.24). The criteria ensure that the on the one hand, are required, there is rule, either as part of initial compliance affirmative defense is available only also case law indicating that in some demonstrations or ongoing compliance where the event that causes an situations it is appropriate for the EPA demonstrations. In reviewing the results exceedance of the emission limit meets to account for the practical realities of of the fuel analyses and the expected the narrow definition of malfunction in technology. For example, in Essex range of results that would be received 40 CFR 63.2 (i.e., sudden, infrequent, Chemical v. Ruckelshaus, 486 F.2d 427, from laboratories conducting the not reasonable preventable and not 433 (D.C. Cir. 1973), the D.C. Circuit proposed analyses, we determined that caused by poor maintenance and or acknowledged that in setting standards too many results would be returned as careless operation). For example, to under CAA section 111 ‘‘variant ‘‘below detection level’’ and, thus, assert the affirmative defense provisions’’ such as provisions allowing provide little information to assist with successfully, the source must prove by for upsets during startup, shutdown and rule implementation and compliance a preponderance of the evidence that equipment malfunction ‘‘appear oversight. Given the costs and efforts excess emissions ‘‘[w]ere caused by a necessary to preserve the reasonableness involved, we determined that the sudden, infrequent, and unavoidable of the standards as a whole and that the proposed fuel analysis requirements failure of air pollution control and record does not support the ‘never to be would not be an effective compliance monitoring equipment, process exceeded’ standard currently in force.’’ monitoring tool for this final rule. equipment, or a process to operate in a See also, Portland Cement Association normal or usual manner * * *’’ The v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 2. Clarification of Testing criteria also are designed to ensure that 1973). Though intervening case law We have clarified that where options steps are taken to correct the such as Sierra Club v. EPA and the CAA for emission limits apply (such as malfunction, to minimize emissions in 1977 amendments calls into question filterable PM versus non-mercury HAP accordance with section 63.10001 and the relevance of these cases today, they metals, or SO2 versus HCl), you need to prevent future malfunctions. For support the EPA’s view that a system only perform stack testing to example, the source must prove by a that incorporates some level of demonstrate compliance with the preponderance of the evidence that flexibility is reasonable. The affirmative selected emission limit. For example, if ‘‘[r]epairs were made as expeditiously as defense simply provides for a defense to you elect to meet the individual non-

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mercury HAP metals standards, you coal-fired units and quarterly HCl and requirements for acid gases at liquid oil- must conduct the Method 29 test for the HF testing, along with site-specific fired EGUs, the final rule requires a site- metals, and you do not have to conduct parameter monitoring for liquid oil-fired specific monitoring plan for those units a Method 5 test for PM. units to ensure compliance with the HCl in this subcategory that demonstrate and HF standards. compliance with the HCl and HF 3. Low Emitting EGU Qualification The continuous monitoring options standards through quarterly We have significantly modified the remain generally intact from the performance tests. With the exception proposed requirements to qualify as a proposed rule, with relatively minor for limited-use liquid oil-fired EGUs and LEE unit for a pollutant other than Hg clarifications concerning calculation of other monitoring options available (such based on an initial performance test. 30-boiler operating day averages and QA as fuel moisture monitoring or HCl/HF Under the proposed rule, the operating requirements. CEMS), the EPA believes this provision limit monitoring provided additional The final rule eliminates all operating will apply to few units. The owner or assurance of compliance for a source limits for PM except for the use of a PM operator will submit the site-specific qualified for non-mercury LEE status CPMS. For the PM CPMS, the final rule plan to identify appropriate parameters based on an initial compliance clarifies procedures for setting this that ensure that the operations of the demonstration. Under the final rule, to operating limit and how it is distinct unit critical to meeting the HCl/HF qualify for LEE status for pollutants from the PM emission limit. The PM emission limits remain consistent with other than Hg, a unit must meet the LEE CPMS will not be correlated as a PM conditions during performance testing. criteria for a series of performance tests CEMS under PS 11 and will produce This will be approved similarly to an over a 3-year period to demonstrate that data in terms of a signal you define. alternative monitoring request. The plan the unit continues to perform well That signal could be milliamps, stack should include the parameters, below the standard for which the source concentration, or other output signal monitoring approach, QA/QC elements, has obtained LEE status. instead of PM emissions in units of the and data reduction (including averaging standard. The operating limit will be set G. Continuous Compliance period) elements. Like the PM CPMS using the highest hourly average operating limit, the operating limit for The most significant changes to the obtained from the PM CPMS during the testing and monitoring requirements acid gas control devices on liquid oil- performance test. Compliance with the fired EGUs will be set using the highest involve the procedures for limit is based on a 30-boiler operating demonstrating continuous compliance. hourly average obtained during the HCl day rolling average basis. However, the and HF performance tests. Compliance The proposed rule contained different final rule also does provide for the use options involving CEMS, periodic stack with the limit is based on a 30-boiler of a PM CEMS to determine compliance operating day rolling average basis. tests, fuel analysis, and various PM and with the filterable PM emission limit if control device operating limits. The the source elects to use this approach. Finally, we have changed the final rule greatly simplifies the The EPA believes that some sources continuous compliance requirements for requirements and provides two basic may be interested in adopting this direct the performance tune-up work practice approaches for most situations: use of approach, and so has included that standard since the proposal. Our intent continuous monitoring (either CEMS or option in the final rule. If this approach was that this work practice standard PM continuous parametric monitoring is selected, the PM CEMS is used as the could be performed in conjunction with system, CPMS) or periodic quarterly direct method of compliance and no routine maintenance operations at a testing. The final rule does not contain additional testing is required other than facility and be a logical extension of the proposed fuel analysis requirements. tests that are required as part of the QA routine best practices for boiler For periodic testing, the proposed rule requirements in PS 11 and Procedure 2. inspection and optimization. Based on required testing every month or every 2 To use this option, the source must elect the comments received, we have months. For those EGU owners or to meet the filterable PM standard, and reduced the required frequency for this operators who choose to use emissions not one of the HAP metals standards. inspection to every 3 years and testing to demonstrate compliance, the Apart from the operating limit for site- provided incentives for neural network final rule requires quarterly filterable specific monitoring associated with combustion management and PM or non-mercury metals HAP, liquid oil-fired EGUs, we removed the optimization practices by providing a whether individual or total metals, other operating limits for control longer interval of 4 years between testing for coal- and liquid oil-fired devices based on a review of the inspections when such systems are in units. The rule requires quarterly HCl comments, after considering other use at a given EGU. testing for coal-fired units and quarterly programs in place to ensure proper H. Emissions Averaging HCl and HF testing, along with site- operations of controls at EGUs. Those specific monitoring for liquid oil-fired other programs include compliance We are finalizing that owners and units to ensure compliance with the HCl assurance monitoring under part 64, operators of existing affected sources and HF standards. The final rule also part 70, and New Source Review permit may demonstrate compliance by has a separate compliance conditions, and other SIP and NSPS emissions averaging for existing EGUs demonstration for those liquid oil-fired requirements for operating and that are located at the same facility that EGUs that have an annual capacity maintaining equipment in accordance are within a single subcategory and that factor of less than 8 percent (emission with good air pollution control rely on emissions testing as the limits do not apply, just the tune-up practices. Those requirements, in compliance demonstration method. In work practice standard). For those EGU combination with the CEMS, PM CPMS, response to our request for comments on owners or operators who choose to use and frequent periodic testing provisions the suitability of emissions averaging emissions testing to demonstrate under the final rule, will enhance the and need for a discount factor, we compliance, the final rule requires monitoring of continuous compliance received a range of suggestions, quarterly filterable PM or non-mercury with the requirements of this rule. including requests for clarification metals HAP, whether individual or total Because the EPA is concerned that regarding eligibility, points for and metals, testing for coal- and liquid oil- there will be little or no monitoring in against the need for a discount factor, fired units; quarterly HCl testing for these underlying applicable and suggestions to ease implementation.

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As we noted at proposal, part of the implementation of the MACT floor allowed to have emissions greater than, EPA’s general policy of encouraging the limits. less than, or equivalent with the use of flexible compliance approaches In the final rule, the EPA is providing emissions limit for their subcategory, where they can be properly monitored that sources may average emissions provided that the average emissions and enforced is to include emissions from existing EGUs at the same facility comprised from individual EGU averaging. Emissions averaging can and within the same subcategory. emissions do not exceed the emissions provide sources the flexibility to comply Further, for Hg emissions only from limit for their subcategory. Averaging in the least costly manner while still existing EGUs within the same across affected units is permitted only if maintaining a regulation that is subcategory, such EGUs in an emissions it can be demonstrated that the total workable and enforceable. Emissions averaging plan may use an alternate quantity of any particular HAP that may averaging would not be applicable to compliance approach consisting of a 90- be emitted by that portion of a new affected sources and could only be boiler operating day rolling average contiguous major source that is subject used between EGUs in the same emission limit of 1.0 lb/TBtu or 1.1E–2 to the same standards in the NESHAP lb/GWh. subcategory at a particular facility. Also, will not be greater under the averaging In the memo entitled ‘‘The Impact of owners or operators of existing sources mechanism than it could be if each Emission Averaging Time on the individual affected EGU in the subject to the EGU NSPS (40 CFR part Stringency of an Emission Standard’’ in subcategory complied separately with 60, subparts D and Da) would be the docket, we have illustrated why a the applicable standard. Under this test, required to continue to meet the PM longer-term average results in a lower the practical outcome of averaging is emission standard of that NSPS limit. In essence, longer-term averages equivalent to compliance with the regardless of whether or not they are allow particularly high (or low) MACT floor limits by each discrete using emissions averaging (i.e., an EGU measurements to be averaged with many EGU, and the statutory requirement that subject to 40 CFR part 60, subpart D or more measurements closer to the mean. the MACT standard reflect the Da must meet its applicable NSPS This results in the highest averages from maximum achievable emissions filterable PM emission limit even if it is a longer-term averaging period (e.g., 90 reductions is, therefore, fully included in a 40 CFR part 63, subpart days) being lower than the highest effectuated. UUUUU, emissions averaging group for averages in a shorter term averaging As noted in the proposal preamble, in filterable PM). period (e.g., 30 days). past rulemakings, the EPA has generally Emissions averaging allows owners We have illustrated this concept by imposed certain limits on the scope and and operators of a facility that includes taking Hg CEMS data and calculating nature of emissions averaging programs. existing EGUs within a subcategory to rolling 30-day averages and rolling 90- These limits include: (1) No averaging demonstrate that the source complies day averages. The 30-day averages have between different types of pollutants; (2) with the proposed emission limits by greater variability and, thus, higher No averaging between sources that are averaging the emissions from an peaks and valleys. The 90-day average not part of the same affected source; (3) individual affected EGU that is emitting has less variability; therefore, the same No averaging between individual unit is able to meet a tighter 90-day above the proposed emission limits with sources within a single major source if limit. the individual sources are not subject to other affected EGUs at the same facility The EPA is providing this alternate that are emitting below the proposed the same NESHAP; and (4) No averaging 90-day rolling average compliance between existing sources and new emission limits and that are within the approach for Hg only. A 90-day rolling same subcategory. Although some sources. average is appropriate for Hg, and only The final rule fully satisfies each of commenters note that the MACT limits for Hg, because the health and these criteria. First, emissions averaging are low, based on the data available to environmental impacts associated with would only be permitted between the Agency, we believe that dozens of Hg are related to environmental loading individual existing sources at a single existing EGUs are achieving all of the rather than shorter term inhalation or stationary source (i.e., the facility), and limits and, thus, emissions averaging is other acute exposure, as is the case with would only be permitted between a possible approach. HCl and PM. We believe that this individual sources in the same The final rule includes an emissions alternative compliance approach will subcategory in the final EGU NESHAP. averaging compliance alternative provide at least the same level of Further, emissions averaging would not because emissions averaging 315 environmental protection while be permitted between two or more represents an equivalent, more flexible, allowing companies greater flexibility to different affected sources. Finally, new and less costly alternative to controlling use emissions averaging. For example, affected sources could not use emissions certain emission points to MACT levels. such an approach would allow for the averaging. Accordingly, we have We have concluded that averaging in averaging of an infrequently operated concluded that the averaging of the proposed rule could be unit that is operating slightly above the emissions across affected units in the implemented and that it would not standard with a more frequently same existing source subcategory is lessen the stringency of the MACT floor operated unit that is operating below the consistent with the CAA. In addition, limits and would provide flexibility in standard in the instances when the more the final rule requires each facility that compliance, cost and energy savings to frequently operated unit is in a multi- intends to utilize emissions averaging to owners and operators. We also day or multi-week maintenance outage. develop an emissions averaging plan, recognize that we must ensure that any The EPA has concluded that it is which provides additional assurance emissions averaging option can be permissible to establish within a that the necessary criteria will be implemented and enforced, will be clear NESHAP a unified compliance regimen followed. In this emissions averaging to sources, and most importantly, will that permits averaging within the same plan, the facility must include the be no less stringent than unit-by-unit facility across individual existing EGUs identification of: (1) All units in the subject to the same standards under averaging group; (2) the control 315 As long as required emission rates are certain conditions. As mentioned technology installed; (3) the process designed to account for factors such as changes in earlier, individual EGUs within an parameter that will be monitored; (4) the averaging times. emissions averaging group would be specific control technology or pollution

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prevention measure to be used; (5) the different subcategories or among EGUs VII. Public Comments and Responses to test plan for the measurement of the not physically located at the same the Proposed NESHAP HAP being averaged; and (6) the affected facility. A. MACT Floor Analysis operating parameters to be monitored I. Notification, Recordkeeping, and for each control device. A state, local, or 1. New Data/Technical Corrections to Reporting tribal regulatory agency that is delegated Old Data authority for this rule could require the Compared to the proposed rule, the reduced continuous compliance Comment: Many commenters emissions averaging plan to be identified errors in the emissions submitted or even approved before requirements in the final rule— primarily reduced testing frequencies database compiled through information emissions averaging could be used. provided by industry in response to the Upon receipt, the regulatory authority and removal of fuel analyses and control 2010 information collection request would not be able to approve an device or fuel operating parameter (ICR) that supported development of emissions averaging plan differing from monitoring—considerably reduces the this rule. Commenters submitted the eligibility criteria contained in the overall burden associated with corrections to the EPA during the public rule. recordkeeping and reporting. Based on The final rule excludes new affected evaluation of the comments received, comment period. sources from the emissions averaging we have established a provision in the Response: The EPA has incorporated provision. The EPA does not believe the final rule for submission of most CEMS technical corrections and new data statute authorizes emissions averaging data (including monitoring plan, submitted prior to the end of the for new affected sources. One reason we emissions data, and QA data) through comment period. The corrections and allow emissions averaging is to give ECMPS, so that the affected industry new data are described in detail in a existing sources flexibility to achieve uses a common reporting tool for memorandum in the docket. The EPA compliance at diverse points with submitting CEMS data. re-ranked the sources in the MACT floor varying degrees of add-on control For data other than most CEMS data, pools to the extent necessary based on already in place in the most cost- the final rule requires electronic the new or corrected data, and we effective and technically reasonable reporting of certain data, including recalculated the MACT floors as fashion. performance test reports, PM CPMS necessary based on the re-ranking of With the monitoring and compliance data, PM CEMS data, and, if approved sources. The revised MACT floors were provisions that are being finalized, there as part of an alternative monitoring established using the same methodology is additional assurance that the request, HAP metals CEMS data. Other set forth in the proposed rule. environmental benefit will be realized. reports, such as notifications, must be 2. Pollutant-by-Pollutant Approach Further, the emissions averaging submitted in hard copy format or in provision would not apply to individual accordance with the procedures Comment: Many commenters raised EGUs if the EGU shares a common stack established by state and local agencies concerns about the way the EPA with units in other subcategories, that receive delegation for implementing determined the MACT floors using a because in that circumstance it is not this rule. In the proposed rule, we took pollutant-by-pollutant approach. possible to distinguish the emissions comment on these approaches and Commenters contended that such a from each individual unit.316 stated our anticipation of adopting these methodology produced limits that are The rule allows EGUs that rely on approaches. In the final rule, we have not achievable in combination, and as CEMS for compliance demonstrations to extended the ECMPS reporting to most such, the limits do not comport with the be able to participate in emissions CEMS data to promote harmonization intent of the statute or the recent court averaging and the emissions limits are for CEMS data from the industry, while decision (NRDC v. EPA, 2007). not subject to a discount. The EPA leaving reporting of non-CEMS data in Commenters further added that the CAA believes that the data certainty provided a separate reporting system. directs the EPA to set standards based by units that use CEMS would be ideal on the overall performance of ‘‘sources’’ J. Technical/Editorial Corrections for emissions averaging and the and CAA sections 112(d)(1), (2), and (3) flexibility and cost-effectiveness it In this final action, we are making a specify that emissions standards be offers. Given the homogeneity of fuels number of technical corrections and established on the ‘‘in practice’’ within the rules subcategories, along clarifications to 40 CFR part 63, subpart performance of a ‘‘source’’ in the with other emissions averaging criteria, UUUUU. These changes clarify category or subcategory. Commenters the Agency believes use of a discount procedures for implementing the stated that if Congress had intended for factor to be unwarranted for this rule. emission limitations for affected the EPA to establish MACT floor levels The emissions averaging provisions in sources. We are also clarifying several considering the achievable emission this final rule are based in part on the definitions to help affected sources limits of individual HAP, it could have emissions averaging provisions in the determine applicability of this rule. We worded CAA section 112(d)(3) to refer Hazardous Organic NESHAP (HON). have modified some proposed to the best-performing sources ‘‘for each The legal basis and rationale for the regulatory language based on public pollutant.’’ Many commenters added HON emissions averaging provisions comments. In addition, in response to that the EPA’s discretion in setting were provided in the preamble to the comments received (including the May standards is limited to distinguishing final HON.317 We do not believe that we 2010 notice from the Utility Air among classes, types, and sizes of have the authority to provide for Regulatory Group (UARG) of calculation sources. Commenters contend that emissions averaging among EGUs in errors in the proposed Hg MACT floor although Congress limited the EPA’s limits), we have checked all calculations authority to parse units and sources 316 The EPA has reviewed monitoring data and made corrections where necessary. with similar design and types, it does submitted to the Agency under the Title IV Acid In several places throughout the not allow the EPA to ‘‘distinguish’’ units Rain Program. Based on that review, the EPA is subpart, including the associated tables, and sources by individual pollutant as unaware of any coal- and oil-fired units that share a common stack. we have corrected the cross-references proposed in this rule (Sierra Club v. 317 Hazardous Organic NESHAP (59 FR 19,425; to other sections and paragraphs of the EPA, 551 F.3d 1019, 1028 (D.C. Cir. April 22, 1994). subpart. 2008)). By calculating each MACT floor

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independently of the other pollutants, HAP or emission control achieved by a basis. One reason for this interpretation commenters contend that the source as a whole. is that a whole plant approach could combination of HAP limits results in a Commenters also stressed that CAA yield least common denominator set of standards that only a hypothetical section 112(d) requires that floors be floors—that is, floors reflecting limited ‘‘best performing’’ unit could achieve. based on actual performance from real or no control, rather than performance Response: We disagree with the facilities. The EPA agrees that this which is the average of what best commenters who believe MACT floors language refers to sources’ actual performers have achieved. See 61 FR cannot be set on a pollutant-by pollutant operation, but again the language says 173687 (April 19, 1996); 62 FR 48363– basis. Contrary to the commenters’ nothing about whether it is referring to 64 (September 15, 1997) (same approach suggestion, CAA section 112(d)(3) does performance as to individual HAP or to adopted under the very similar language not mandate a total facility approach. A single facility’s performance for all of CAA section 129(a)(2)). Such an reasonable interpretation of CAA HAP. Industry commenters also said approach would allow the performance section 112(d)(3) is that MACT floors that Congress could have mandated a of sources that are outside of the best- may be established on a HAP-by-HAP HAP-by-HAP result by using the phrase performing 12 percent for certain basis, so that there can be different ‘‘for each HAP’’ at appropriate points in pollutants to be included in the floor pools of best performers for each HAP. CAA section 112(d). The fact that calculations for those same pollutants, Indeed, as illustrated below, the total Congress did not do so does not compel and it is even conceivable that the worst facility approach not only is not any inference that Congress was sub- performing source for a pollutant could compelled by the statutory language but silentio mandating a different result be considered a best performer overall, can lead to results so arbitrary that the when it left the provision ambiguous on a result Congress could not have approach may simply not be legally this issue. The argument that MACT intended. Inclusion of units that are permissible. floors set HAP-by-HAP are based on the outside of the best performing 12 Clean Air Act section 112(d)(3) is not performance of a hypothetical facility, percent for particular pollutants would explicit as to whether the MACT floor so that the limitations are not based on lead to emission limits that do not meet is to be based on the performance of an those achieved in practice, just the requirements of the statute. entire source or on the performance reiterates the question of whether CAA For example, if the best performing 12 achieved in controlling particular HAP. section 112(d)(3) refers to whole percent of facilities for HAP metals were Congress specified in CAA section facilities or individual HAP. All of the also the worst performing units for acid 112(d)(3) the minimum level of limitations in the floors in this rule gas HAP and the best performers for emission reduction that could satisfy reflect sources’ actual performance and acid gas HAP were the worst performers the requirement to adopt MACT. For were achieved in practice. As to for HAP metals, the floor for acid gases new sources, this floor level is to be commenters’ claims that standards set or metals would end up not reflecting ‘‘the emission control that is achieved in in this manner cannot be met by any best performance. In such a situation, practice by the best controlled similar actual sources, we have determined that the EPA would have to make a value source.’’ For existing sources, the floor there are approximately 69 existing judgment as to which pollutant level is to be ‘‘the average emission coal-fired EGUs that meet all of the final reductions were most critical to decide limitation achieved by the best existing source MACT emission limits which sources are best controlled.318 performing 12 percent of the existing (out of 252 EGUs that reported data for Such value judgments are antithetical to sources’’ for categories and Hg, PM, and HCl in the 2010 ICR) and the direction of the statute at the MACT subcategories with 30 or more sources, at least one EGU that meets all of the floor-setting stage. or ‘‘the average emission limitation final new source MACT emission limits. Commenters suggested that a multi- achieved by the best performing 5 Commenters also point to the EPA’s pollutant approach could be sources’’ for categories and subcategorization authority, and claim implemented by weighting pollutants subcategories with fewer than 30 that because Congress authorized the according to relative toxicity and sources. Commenters point to the EPA to distinguish among classes, types, calculating weighted emissions totals to statute’s reference to the best performing and sizes of units, the EPA cannot use as a basis for identifying and ‘‘sources,’’ and claim that Congress distinguish units by individual ranking best performers. This suggested would have specifically referred to the pollutant, as they allege the EPA did in approach would require the EPA to best performing sources ‘‘for each the proposed rule. However, that essentially prioritize the regulated HAP pollutant’’ if it intended for the EPA to statutory language addresses the EPA’s based on relative risk to human health establish MACT floors separately for authority to subcategorize sources of each pollutant, where risk is a each HAP. within a source category prior to setting criterion that has no place in the The EPA disagrees. The language of standards, which the EPA has done for establishment of MACT floors, which the Act does not address whether floor certain EGUs. The EPA is not are required by statute to be based on levels can be established HAP-by-HAP distinguishing within each subcategory technology. or by any other means. The reference to based on HAP emitted. Rather, it is The central purpose of the amended ‘‘sources’’ does not lead to the establishing emissions standards based air toxics provisions was to apply strict assumption the commenters make that on the emissions limits achieved by technology-based emission controls on the best performing sources can only be units in each subcategory. Therefore, the HAP. See, e.g., H. Rep. No. 952, 101st the best-performing sources for the EPA’s subcategorization authority is Cong. 2d sess. 338. An interpretation entire suite of regulated HAP. Instead, irrelevant to the question of how the that the floor level of control must be the language can be reasonably EPA establishes MACT floor standards limited by the performance of devices interpreted as referring to the source as once it has made the decision to a whole or to performance as to a distinguish among sources and create 318 See Petitioners Brief in Medical Waste particular HAP. Similarly, the reference subcategories. Institute et al. v. EPA, No. 09–1297 (D.C. Cir.) in the new source MACT floor provision The EPA’s long-standing pointing out, in this context, that ‘‘the best performers for some pollutants are the worst to ‘‘emission control achieved by the interpretation of the Act is that the performers for others’’ (p. 34) and ‘‘[s]ome of the best controlled similar source’’ can existing and new source MACT floors best performers for certain pollutants are among the mean emission control as to a particular are to be established on a HAP-by-HAP worst performers for others.’’

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that only control some of these 3. Minimum Number of EGUs To Set suggested that the detection levels pollutants effectively guts the standards Floors should be replaced using a value of half by including worse performers in the Comment: Many commenters the method detection limit (MDL). Many averaging process, whereas the EPA’s indicated that CAA section 112 requires other commenters stated that data that interpretation promotes the evident that data from a minimum of 5 units are are below the detection limit should not Congressional objective of having the required to set MACT floors for existing be used in setting the floors, and these floor reflect the average performance of sources. Commenters noted that the data should be replaced with a higher best performing sources. Because EPA’s use of less than 5 units for value including either the MDL, limit of Congress has not spoken to the precise subcategories with greater than 30 units quantitation (LOQ), practical quantitation limit (PQL), or reporting question at issue, and the Agency’s is a legalistic reading of CAA section interpretation effectuates statutory goals limit (RL) for the purposes of the MACT 112 that could result in such absurd and policies in a reasonable manner, its floor calculations. Other commenters results as using 5 units to set MACT interpretation must be upheld. See stated all non-detect values should be floors for a subcategory with 29 units Chevron v. NRDC, 467 U.S. 837 excluded from the floor analysis, or all and data for only 10 units, but using a (1984).319 values should be treated as zero. The EPA notes, however, that if single unit to set MACT floors for a Some commenters stated it is optimized performance for different subcategory with 31 units and data for necessary to keep the data as reported HAP is not technologically possible due only 10 units. because changing values would lead to to mutually inconsistent control Response: The EPA does not agree an upward bias. Additional commenters technologies (for example, if metals that CAA section 112(d)(3) mandates a agreed with this basic premise, but performance decreased as organics minimum of 5 sources in all instances, suggested that replacing non-detect data reduction is optimized), then this would notwithstanding the incongruity of with a value of half the MDL is have to be taken into account by the having less data to establish floors for appropriate while still minimizing the EPA in establishing a floor (or floors). larger source categories than is bias. They noted that treating The Senate Report indicates that if mandated for smaller ones. The literal measurements below the MDL as certain types of otherwise needed language of the provision appears to occurring at the MDL is statistically controls are mutually exclusive, the compel this result. CAA section incorrect and violates the statute’s EPA is to optimize the part of the 112(d)(3) states that for categories and ‘‘shall not be less stringent than’’ standard providing the most subcategories with at least 30 sources, requirement for MACT floors. One environmental protection. S. Rep. No. the MACT floor for existing sources commenter also provided a reference for 228, 101st Cong. 1st sess. 168 (although, shall be no less stringent than the a statistical method based on a log- as noted, the bill accompanying this average emission limitation achieved by normal distribution of the data which Report contained no floor provisions). It the best-performing 12 percent of the estimated the ‘‘maximum likelihood’’ of should be emphasized, however, that sources for which the Administrator has data values; this result is slightly higher the D.C. Circuit has stated that ‘‘the fact emissions information. The plain than half the MDL. that no plant has been shown to be able language of this provision requires the Some commenters stated that it is to meet all of the limitations does not use of fewer data points for large source necessary to substitute the MDL value demonstrate that all the limitations are categories than for small source when performing the MACT floor not achievable.’’ Chemical categories where the Administrator only calculations. With MDL defined as the Manufacturers Association v. EPA, 885 has emissions information on a small lowest concentration that can be F. 2d at 264 (upholding technology- number of units for categories and distinguished from the blank at a based standards based on best subcategories with 30 or more sources. defined level of statistical significance, performance for each pollutant by Furthermore, commenters contend that this is an appropriate value. If MDL different plants, where at least one plant Congress could not have intended the values are not reported, one commenter met each of the limitations but no single floors for a subcategory with 29 sources suggested an approach for estimating an plant met all of them). to be based on 5 sources and a MDL equivalent value, but recognized All available data for EGUs indicate subcategory with 31 sources to be based that the background laboratory and test that there is no technical problem on less than that number; but we report files may not be available to the achieving the floor levels contained in maintain this contention is without EPA in order to derive these estimates. this final rule for each HAP merit because 12 percent of 31 is 3.72 Most commenters representing simultaneously, using the MACT floor (rounded to 4) so the EPA would not industry and industry trade groups technology. Data demonstrating a base standards for a subcategory with 31 argued that either LOQ or PQL values technical conflict in meeting all of the sources on 5 sources even if we had data should replace non-detects. The LOQ is limits have not been provided, and, as on all 31 sources in the subcategory. For defined as the smallest concentration of stated above, based on the available these reasons, we decline to adopt the analyte which can be measured. data, there are approximately 64 EGUs commenters’ position and continue to These commenters contended that the that meet all of the final existing source adhere to the clear statutory directive. LOQ leads to a quantifiable amount of emission limits and at least one EGU the substance with an acceptable level 4. Treatment of Detection Levels that meets all of the final new source of uncertainty. A few commenters emission limits. Comment: Commenters stated that provided calculations showing some of when setting the MACT floors, non- the proposed MACT floors were below 319 Because industry commenters argued that the detect values are present in many of the the LOQ. Additionally, some of these statute can only be read to allow floors to be datasets from best performing units. commenters stated that using LOQ or determined on a single source basis, commenters offered no view of why their reading could be Commenters provided input on how PQL values also incorporates additional viewed as reasonable in light of the statute’s goals these non-detect values should be sources of random and inherent and objectives. It is not evident how any statutory treated in the MACT floor analysis. sampling error throughout the testing goal is promoted by an interpretation that allows Some commenters agreed that it is process, which is necessary. These floors to be determined in a manner likely to result in floors reflecting emissions from worst or appropriate to keep the detection levels errors occur during sample collection, mediocre performers. as reported, while certain commenters sample recovery, and sample analysis;

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MDL values only account for method reported non-detect data. Other √3 of the true concentration. This specific (e.g., instrument) errors. These commenters disagreed with this method relationship translates to an expected commenters contended that the three and claimed that it would lead to results measurement imprecision for an times the MDL approach discussed in which introduce a high bias in the floor emissions value occurring at or near the the proposal accounts for some setting process. A few contended that method detection level of about 40 to 50 measurement errors but does not multiplying by 3 would introduce a 300 percent. account for these unavoidable sampling percent error into the floor, resulting in By assuming a similar distribution of errors. The commenters also noted that a floor that is less stringent than measurements across a range of values an LOQ is calculated as 3.18 times the required by the Act. Others suggested and increasing the mean value to a MDL, and PQL is calculated as 5 to 10 that the MDL values are antiquated and representative higher value (e.g., 3 times times the MDL. Many of the already too high and thus it is not minimum detection level or 3xMDL), commenters in support of using either appropriate to multiply them by three. we can estimate measurement an LOQ or PQL value ultimately Also, a few commenters suggested imprecision at other levels. For an believed a work practice is more multiplying the MDL by three would assumed 3xMDL, the estimated appropriate where a MACT floor limit is not reflect the actual lower emissions measurement imprecision for a three below either of these two values. They achieved by any source and as such is test run average value would be on the cited CAA section 112(h)(1) which unlawful under CAA section 112(d). order 10 to 20 percent. This is about the allows work practices under CAA Response: We agree with many of the same measurement imprecision as section 112(h)(2) if ‘‘the application of comments related to treatment of data found for Methods 23 and 29 indicated measurement methodology to a reported as detection limit values in the in the ASME ReMAP study for the particular class of sources is not development of MACT floors and sample volumes prescribed in the final practicable due to technological and emissions limits. As we noted at rule (e.g., 4 to 6 dscm) for multiple tests. economic limitations’’. These proposal, the statistical probability Analytical laboratories often report a commenters stated that the inability of procedures applied in calculating the value above the method detection limit sources to accurately measure a floor or an emissions limit inherently that represents the laboratory’s pollutant at the level of the MACT floor and reasonably account for emissions perceived confidence in the quality of qualifies as such a technological data variability including measurement the value. This independently adjusted limitation that warrants a work practice imprecision when the database value is expressed differently by various standard. represents multiple tests from multiple laboratories and is called LOQ, PQL, or Commenters stated that where the emissions units for which all of the data RL. In many cases, the LOQ, PQL, or RL proposed MACT floor is below the LOQ are measured significantly above the is simply a multiplication of the method or PQL then that source category has a method detection level. That is less true detection limit. Commonly used technological measurement limitation. when the database includes emissions multipliers range from 3 to 10. Because A few commenters suggested RL values occurring below method detection these values reflect individual should be used when developing the capabilities regardless of how those data laboratories’ perceived confidence, and, floor limits. They stated that the RL is are reported. therefore, could be viewed as arbitrary, the lowest level at which the entire The EPA’s guidance to respondents we decline to adopt the LOQ, PQL, or analytical system gives reliable signals for reporting pollutant emissions used RL because such approaches in our view and includes an acceptable calibration to support the data collection specified would inappropriately inflate the MACT point. They added that use of an the criteria for determining test-specific floor standards. Our alternative to those acceptable calibration point is critical in method detection levels. Those criteria inconsistent approaches is discussed showing that numbers are real versus ensure that there is only about a 1 below. multiplying the MDL by various factors. percent probability of an error in Consistent with findings expressed in Several commenters stated that all deciding that the pollutant measured at reports of emissions measurement non-detect values should be excluded the method detection level is present imprecision and the practices of from MACT floor calculations. They when in fact it was absent. (Reference: analytical laboratories, we believe that believed that excluding all non-detect ReMAP: PHASE 1, Precision of Manual using a measurement value of 3 times a values would eliminate any potential Stack Emission Measurements; representative method detection limit errors or accuracy issues related to American Society of Mechanical established in a manner that assures 99 testing for compliance. Due to Engineers, Research Committee on percent confidence of a measurement inconsistencies of the MDL value Industrial and Municipal Waste, above zero will produce a representative reported for non-detect data, one February 2001.) Such a probability is method reporting limit suitable for commenter suggested treating all such also called a false positive or the alpha, establishing regulatory floor values. values as zero. This would provide a Type I, error. This means specifically On the other hand, we also agree with consistent approach for setting the floor that for a normally distributed set of commenters that an emissions limit set as well as determining compliance. measurement data, 99 out of 100 single from a small subset of data or data from Several commenters provided input measurements will fall within ±2.54 × a single source may be significantly on the EPA’s proposed method of three standard deviation of the true different than the actual method times the MDL as an option for setting concentration. The anticipated range for detection levels achieved by the best limits. A few commenters in support the average of repeated measurements performing units in practice. This fact, noted that this approach provided a comes progressively closer to the true combined with the low levels of reasonable method to account for data concentration. More precisely, the emissions measured from many of the variability as it took into account more anticipated range varies inversely with best performing units, led the EPA since than just analytical instrument the square root of the number of proposal to review and revise the precision. Many other commenters measurements. Thus, for a known procedure intended to account for the argued that this method results in limits standard deviation (SD) of anticipated contribution of measurement which are too low, namely that it is still single measurements, the anticipated imprecision to data variability in lower than the LOQ value which they range for 99 out of 100 future triplicate establishing effective emissions limits. are in favor of as a substitute for any measurements will fall within ±2.54 SD/ In response to the comments about the

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quality of measurements at very low floor or emissions limit (UPL) which antagonistic effects that adding multiple emissions limits especially for new results in a concentration where the pollution control devices can have on sources, we revised the procedure for method would produce measurement an EGU’s HAP emissions. Commenters identifying a representative method accuracy on the order of 10 to 20 indicated that EGUs would not be able detection level (RDL). percent similar to other EPA test to comply with the proposed new The revised procedure for methods and the results found in the source HCl limit without adding a determining an RDL starts with ASME ReMAP study. scrubber or some type of sorbent identifying all of the available reported We determined the RDL for each injection to control HCl emissions. pollutant-specific method detection pollutant using data from tests of all the Adding these HCl control technologies levels for the best performing units best performers for all of the final will increase the total PM emissions of regardless of any subcategory (e.g., regulatory subcategories (i.e., pooled these units. According to commenters, existing or new, fuel type, etc.). From test data). We applied the same because a fabric filter-alone that combined pool of data, we calculate pollutant-specific RDL and emissions configuration (the basis for the new the arithmetic mean value. By limiting limit assessment and adjustment source PM limit) would not meet all the data set to those tests used to procedures to all subcategories for MACT limits, these units may not be the establish the floor or emissions limit which we established emissions limits. best-performing units. (i.e., best performers), which in this case We believe that adjusting emissions Response: The EPA disagrees with the is a larger data set than normally limits in this manner, which ensures commenters’ statements that no existing available for establishing NESHAP, we that measurement variability is unit is currently meeting the new source believe that the result is representative adequately addressed relative to limits. The EPA established the new of the best performing testing companies compliance determinations, is a better source limits based on data from and laboratories using the most procedure than the one applied at existing EGUs and there is at least one sensitive analytical procedures. We proposal, which was based on more EGU, based on the data available, that believe that the outcome should limited data. We also believe that is meeting all three final HAP limits and minimize the effect of a test(s) with an currently available emissions testing at least eight EGUs that are meeting one inordinately high method detection procedures and technologies provide or more of the new source limits. As a level (e.g., the sample volume was too the measurement certainty sufficient for result of comments received on the full small, the laboratory technique was sources to demonstrate compliance at body of data, the EPA has re-ranked the insufficiently sensitive, or the procedure the levels of the revised emissions best performing EGUs and reviewed the for determining the minimum value for limits. new source limits based on the re- reporting was other than the detection ranking where appropriate. Based on the 5. Basis for New Source MACT level). We then call the resulting mean revised ranking, the best performing of the method detection levels the Comment: Several commenters stated source for PM has changed and that representative detection level (RDL) that the proposed limits set for new source now forms the basis for the new because it is characteristic of accepted EGUs do not represent the best source filterable PM limit in the final source emissions measurement performing EGU. The commenters state rule. The source is a coal-fired EGU that performance. that the EPA has chosen the strictest includes the entire suite of controls that The second step in the process is to limit irrespective of the EGU and that would likely be required on a new coal- calculate 3xRDL to compare with the limits for new EGUs should be fired source constructed prospectively calculated floor or emissions limit. This achievable. According to the (i.e., it is a unit with SCR, dry FGD, and step is similar to what we have used for commenters, no existing EGU is FF). Thus, the commenters’ concerns are other NESHAP including the Portland currently meeting the proposed limits, no longer relevant as they relate to PM Cement rule. As outlined above, we use which will result in a moratorium on emissions from coal-fired EGUs. the multiplication factor of 3 to reduce the construction of new coal-fired EGUs. The EPA also believes that the EGUs the imprecision of the analytical method Further, commenters state that another serving as the basis for the new source until the imprecision in the field result of the EPA’s flawed approach is Hg and HCl limits in the final rule are sampling reflects the relative method that the proposed standards for new representative of what a new coal-fired precision as estimated by the ASME EGUs are so low that adequate test EGU would look like to meet all of the ReMAP study. That study indicates that methodologies to demonstrate requisite regulations applicable to EGUs such relative imprecision remains a compliance do not exist. Without (e.g., NSPS and the CSAPR) as they also constant 10 to 20 percent over the range accurate testing methodologies, include the entire suite of controls that of the method. For assessing the commenters assert that contractors will would likely be required on a new coal- calculated floor results relative to not guarantee that potential emission fired source constructed prospectively. measurement method capabilities, if control technologies will meet the The EPA has also taken into account the 3xRDL were less than the calculated proposed standards. Without accurate ability of the various test methods to floor or emissions limit (e.g., calculated test methodologies and vendor accurately measure emissions at the from the upper predictive limit, UPL), guarantees, commenters believe that levels being demonstrated by the EGUs we would conclude that measurement financing of new facilities will be in the top performing 12 percent in variability was adequately addressed virtually impossible to secure which establishing the final limits, and we with the initial floor calculation. The will, in turn, effectively preclude the have determined that there are adequate calculated floor or emissions limit construction of any new coal-based test methods to measure the regulated would need no adjustment. If, on the EGUs. HAP at the new source levels. other hand, the value equal to 3xRDL Commenters also stated that the EPA were greater than the UPL, we would failed to address cumulative effects of 6. Achievability of Limits conclude that the calculated floor or using multiple pollution control devices Comment: A number of commenters emissions limit did not account entirely in determining MACT levels applicable state that the EPA has chosen the for measurement variability. Where to PM levels. In proposing total PM as strictest limit irrespective of the unit such was the case, we substituted the a surrogate, commenters believe that the and that limits for new EGUs should be value equal to 3xRDL for the calculated EPA failed to consider or address the achievable. According to the

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commenters, no existing unit is ability to meet the EPA’s similarly CAA section 112(g) standards issued by currently meeting the proposed new ‘‘cherry-picked’’ total PM floor standard. certain state agencies has no bearing on source limits, which will result in a The commenters state that, for the legitimacy of the standards at issue moratorium on the construction of new existing sources as with the new source here. coal-fired units. The commenters state standard-setting approach, a pollutant- The EPA agrees with commenters that that this regulation goes beyond by-pollutant approach does not consider the SO2 and some Hg controls may add protecting public health and will impact what the top performing 12 percent to the PM loading and that it is the country’s choice of fuel for energy achieve in practice for all pollutants and reasonable to establish the new source production. Other commenters state that does not consider the antagonistic standard based on an EGU that has a another result of the EPA’s flawed effects of the concurrent use of various suite of controls that will be required of approach is that the proposed standards control technologies. For example, one any new source. For example, new coal- for new units are so low that adequate commenter states that 47 of the 131 fired EGUs will be required to comply test methodologies to demonstrate sources used to calculate the existing with the utility NSPS and may have to compliance do not exist. Without source total PM limit only had PM comply with the CSAPR and other accurate testing methodologies, control but no acid gas or Hg controls requirements (e.g., SIP or state-only commenters allege that contractors will that could emit additional PM. requirements). Commenters are also not guarantee that potential emission According to the commenter, the CAA correct that the proposed new source control technologies will meet the is clear that standards must be based on PM surrogate standard was based on a proposed standards. Without accurate actual sources and not the product of a source that is not like a coal-fired EGU test methodologies and vendor pollutant-by-pollutant determination that would be constructed today (i.e., an guarantees, commenters believe that resulting in a set of composite standards EGU with only PM control and no SO2 financing of new facilities will be that do not necessarily reflect the controls). virtually impossible to secure, and that overall performance of any actual The final standard is not based on the this in turn will effectively preclude the source. To address these issues, the source used to establish the proposed construction of any new coal-based commenter recommends that the EPA limit. As stated above, industry units. Commenters maintain that use an approach that more accurately commenters provided data corrections adopting standards effectively banning reflects what actual best performing and new data and the EPA considered new coal units amounts to a momentous sources achieve. that new and revised data in change in national energy policy Response: The EPA disagrees with the establishing the final standards. We re- without discussion or analysis and far commenters’ contention that the ranked all the coal-fired EGUs based on exceeds the EPA’s authority. pollutant-by-pollutant approach to the new data. The new ranking of coal- establishing MACT floors is inconsistent fired EGUs resulted in a change of the Some commenters add that the with the CAA for the reasons set forth source we used to establish the new proposed new source MACT standards in the response to comments on the source PM surrogate standard for non- do not represent rates that have been EPA’s MACT floor setting process. In mercury metal HAP. The basis for the achieved in practice and are orders of addition, the EPA established the new source limit in the final rule is a magnitude lower than any of the CAA proposed new source limits based on unit that has a full suite of controls section 112(g) case-by-case MACT limits data from existing EGUs, and there are similar to what would be required for established for the most advanced units EGUs that are able to meet the new any new coal-fired EGUs (i.e., it is a unit in the U.S. coal fleet by multiple state source limits. To the extent the with SCR, dry FGD, and FF). The EPA agencies. commenters are concerned that no has identified at least one EGU meeting Other commenters stated that the existing source is simultaneously all of the final new source limits; thus, synergistic impact of multiple controls meeting all of the new sources limits, the EPA does not believe that it is has not been taken into account in the we note that the EPA has revised the finalizing standards that ‘‘ban’’ new proposed rules. Commenters argue that new source standards based on coal-fired generation as indicated by the circumstances exist with respect to the comments and data corrections that commenter. control of acid gases, which will require industry made to data it incorrectly The EPA also disagrees that the final scrubbers or other SO2 controls that add provided in response to the utility ICR. new source standards are so stringent particulate to the flue gas stream, and We have identified at least one source that there are not adequate test methods that added particulate must be removed that is meeting all of the new source available to determine compliance with by PM control devices along with the MACT limits in the final rule. the standards. The EPA has taken into particulate added to the flue gas for We disagree with commenters that account the ability of the various test EGUs that need to install ACI for Hg suggest the proposed new source methods to accurately measure control. Because particulate devices standards are invalid because they are emissions at the levels being provide a fixed percent reduction of more stringent than CAA section 112(g) demonstrated by the best performing particulate, commenters assert that it is case-by-case MACT limits established EGUs in establishing the final limits. mathematically certain that PM by state agencies. As commenters note, This has been done through use of the performance will decrease because states, not the EPA, established the CAA 3XRDL (discussed elsewhere in this control of both acid gases and Hg would section 112(g) standards, and they did preamble and the Response to add PM to the flue gas stream which so based on the information available to Comments document) and through would in turn decrease performance of them. The EPA likewise must establish adjustments to the sampling time the PM control on the relevant mass CAA section 112(d) standards based on requirements for certain of the HAP. metric. As a consequence, commenters the available data. We have considered allege that there is no assurance that the available data and information, 7. Comments on Technical Approaches sources can meet the EPA’s ‘‘cherry- including the 2010 ICR data, and Comment: Commenters disagreed picked’’ floors for acid gases and for Hg complied with the requirements of CAA with the EPA’s use of data from by ‘‘optimizing’’ these systems to meet section 112(d) in establishing the multiple units exhausting through a the performance of the floor units standards in this final rule. That the common stack and argued that the EPA because to do so would impact their final standards are more stringent than unreasonably treated data from multiple

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units exhausting through a single stack stack measurement to represent Hg be based on a specific technology; as multiple data points in establishing emissions from the facility’s other commenters are advocating that a the MACT floors. The commenters stacks. percent reduction format would specify believe it is improper to count a single Response: The EPA disagrees with the level or reduction but would not data point from a multiple-unit common commenters. As in the major-source dictate any specific control or stack as multiple data points. The Industrial Boiler NESHAP, the EPA methodology. commenters state that where two units continues to believe that the emissions Comments were also received that exhaust through a common stack, the from the common stack represent the some state programs contain Hg performance is not that of two sources, average emissions of the EGUs emission limits that are more stringent but only one. The commenters indicate exhausting to the common stack and are than the EPA’s proposed emission that emissions performance that is representative of both EGUs. limits. The programs of Connecticut, actually achieved reflects combined Commenters have provided no data to Massachusetts, New Hampshire, New operation, which cannot rationally be support the contention that this Jersey, and New York were noted. split into two parts (data points) because assumption is false. In addition, Commenters provided information on this emissions performance was not commenters’ contention that distinct these states’ Hg emission limits, which achieved by two separate sources. EGUs (i.e., boilers) are one source if they often are in the form of either a lb/TBtu Commenters assert that although it may emit out of a common stack is not format or a percent reduction. be acceptable for the EPA to surmise consistent with the CAA section Commenters noted that EGUs in these that the combined performance of 112(a)(8) definition, which clearly states were in compliance with the state multiple EGUs and pollution control applies to the individual boiler units regulations and, therefore, the EPA’s devices represents an emissions control with a capacity of more than 25 MW. It emission limits should be more strategy that could be a best performer, would not be reasonable in light of that stringent. thereby entitling the Agency to use the definition to consider the emissions Response: The EPA disagrees with the data at all, the fact is there is only one from two boilers to a common stack as commenters’ suggestion that a percent performer not two. Commenters contend the emissions of one EGU. The EPA reduction standard should be included that apart from being inconsistent with only used data from combined stacks in the final rule. The EPA notes that the applicable MACT case law, counting where both EGUs were operating or inability to account for Hg removed combined stack emissions as two or where the owner/operator certified that from the coal prior to combustion was more data points is unreasonable no air leakage could occur. The EPA not the only reason provided for not because it dampens variability and over- expects that companies will comply using a percent reduction format. As represents the emissions data by with the final rule by conducting testing noted in the proposal preamble (76 FR 25040), we did consider using a percent creating multiple ‘‘performers’’ or at the common stack as that is usually reduction format for Hg. We determined sources when there is in fact only one. where the sampling locations are (rather not to propose a percent reduction Commenters note that in the major- than in the intermediate ductwork) and standard for several reasons. The source Industrial Boiler NESHAP, the will report the results as being for each percent reduction format for Hg and EPA argued its approach of creating two EGU. The EPA has reviewed the data based other HAP emissions would not have data points from a single combined on comments received and does not addressed the EPA’s desire to promote, stack data point is reasonable because it believe that there are any and give credit for, coal preparation cannot separate the comingled fraction inconsistencies in the data set used for practices that remove Hg and other HAP of the emissions from the different the final rule. In the MACT floor before firing because we did not have emission points. Commenters state that analysis, the EPA only used data from the data to account for those practices. this is irrelevant, believing that there is stacks that were tested or for which test Specifically, to account for the coal no basis to separate these emissions data were provided. These stack preparation practices, sources would be because the MACT floor is based on best measurements were not used to required to track the HAP performing sources and there is only a represent emissions from other, non- concentrations in coal from the mine to single source. tested, stacks in the MACT analysis. the stack, and not just before and after According to commenters, the EPA the control device(s). Such an approach 8. Alternative Units for Emission Limits cannot determine what amount of the would be difficult to implement and overall performance of a combined stack Comment: Several commenters enforce. Moreover, we do not have the data point is the specific result of the submitted a variety of alternatives to the data necessary to establish percent combination. Commenters assert that input- or output-based MACT floor reduction standards for HAP at this the EPA also argues that applying the limits as means of establishing the time. Depending on what was emissions equally to multiple units MACT floors. Some commenters considered to be the ‘‘inlet’’ and the exhausting through a single stack suggested emission reductions or degree to which precombustion removal ‘‘accurately represents the emissions of removal efficiencies. These commenters of HAP was desired to be included in those units on average.’’ Commenters suggest that a percent reduction MACT the calculation, the EPA would need believe that is simply not correct and metric be considered as an alternative, (e.g.) the HAP content of the coal as it there is no plausible factual basis for and not a substitute, to some of the left the mine face, as it entered the coal that statement, believing that there is no proposed MACT numerical limits, preparation facility, as it left the coal unit that ‘‘achieved’’ those emissions. particularly those that appear too preparation facility, as it entered the Rather, the data represent the combined problematic to meet in reality. A EGU, as it entered the control devices, weighted average of two units, without necessary data format and protocol and as it left the stack to be able to knowing how either unit actually could be developed for some HAP, such establish percent reduction standards. performed. One commenter also stated as Hg, that would allow an appropriate We do not have this type of information. that in several instances when a facility percent reduction alternative to be The EPA believes that an emission operated tandem or multiple EGUs but developed. Commenters believe that the rate format allows for, and promotes, the only submitted a single stack Brick MACT decision stands for the use of pre-combustion HAP removal measurement, the EPA used the single proposition that a MACT level cannot processes because such practices will

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help sources assure they will comply the EPA’s proposed beyond-the-floor subcategory are meeting the final with the proposed standard. A percent limit is based on only three samples beyond-the-floor limit based on reduction requirement would likely from a single test held at only one EGU, available data (see the MACT Floor limit the flexibility of the regulated which is not enough data to develop analyses in the docket), and, in any community by requiring the use of a such a limit, especially as more data case, CAA section 112(d) does not control device. In addition, as discussed were available for this EGU in the require that a specified percentage of in the Portland Cement NESHAP (75 FR database. Commenters noted that sources in a category or subcategory be 55002; September 9, 2010), the EPA although this one EGU may have been able to meet the MACT standard that is believes that a percent reduction format able to achieve the proposed limit established. This is even truer for negates the contribution of HAP inputs during this one test, the three samples beyond-the-floor standards which are to EGU performance and, thus, may be are not adequate to demonstrate the set at levels beyond what the average of inconsistent with the D.C. Circuit’s long-term ability of this EGU to meet the best performing sources are rulings as restated in the Brick case (479 that limit consistently, let alone the achieving in practice and instead based F.3d at 880) which say, in effect, that it long-term abilities of the top 12 percent on what is achievable. Commenters is the emissions achieved in practice of all low rank coal EGUs to meet that have failed to provide any data that (i.e., emissions to the atmosphere) that limit consistently. Given Texas lignite’s supports the contention that some EGUs matter, not how one achieves those particularly high rates of variability of in the subcategory will not be able to emissions. Hg concentration, and the inability to achieve the standards with additional The 2010 ICR data confirm that plant minimize this variability, the controls. inputs likely play a role in emissions to commenters believe that the EPA is Comment: Commenters indicated that the atmosphere. These data indicate that obliged to have more, not less, data to the EPA has not justified a beyond-the- some EGUs are achieving lower Hg support the proposed beyond-the-floor floor limit for Hg for new IGCC units. emissions to the atmosphere at a lower Hg limit for low rank coal EGUs. One The EPA’s choice of the beyond-the- Hg percent reduction (e.g., 75 to 85 commenter added that the EPA’s floor Hg limit for new IGCCs is not percent) than are other EGUs with decision to require a beyond-the-floor derived from IGCC test data from the higher percent reductions (e.g., 90 limit for the low rank virgin coal 2010 ICR and commenters allege that percent or greater). However, we are not subcategory does not comply with CAA the EPA has not provided adequate sure whether these data accurately section 112(d)(2). Some commenters justification for its decision from a reflect the total percent reduction mine- also contended that the EPA failed to technology capability assessment. to-stack because we do not have all the include the cost of a baghouse in its Commenters note that ACI for Hg data necessary to make that beyond-the-floor analysis. They note treatment of coal-derived syngas is not determination. Thus, we proposed to that, according to the EPA, in order to in use in any operating IGCC plant establish numerical emission standards comply with the proposed EGU MACT today, nor can it be used in the same for Hg HAP emissions from EGUs and rule, units will either fuel switch to a fashion as it is used at conventional we are finalizing numerical emission lower Hg fuel or retrofit air pollution coal-fired EGUs. Commenters assert that standards. The same issues prevent us controls. the EPA also lacks data with respect to from considering percent reduction Response: The EPA notes that all of new IGCC units, yet the EPA proposed standards for the other HAP emitted the low rank virgin coal-fired EGUs for beyond-the-floor MACT limits for new from EGUs. which data were submitted in response IGCC sources. The commenters assert With regard to the comments relating to the 2010 ICR were meeting the Hg that the EPA’s limits for new IGCC to some state programs being more floor limit (11 lb/TBtu). Four of the sources are based on beliefs, stringent than the EPA’s proposed EGUs have ACI systems installed and predictions, projections and design limits, the EPA would note that many of three of the four EGUs tested were also target assumptions. The limits from the the programs identified by one meeting the beyond-the-floor Hg 2007 DOE Report referenced in the commenter have an ‘‘either/or’’ format emission limit of 4.0 lb/TBtu. Those preamble are based on environmental for their Hg standards. That is, an EGU three units were achieving control levels target assumptions. These IGCC can either meet an emission limit (e.g., of greater than 95 percent (fuel to stack). environmental targets were chosen to lb/TBtu) or achieve a percent reduction. The other low rank virgin coal-fired match Electric Power Research Institute The commenter did not note which EGUs that are not currently meeting the (EPRI) design basis from their Coal Fleet form of the standard the EGUs were beyond-the-floor emission limit do not for Tomorrow Initiative. Commenter meeting so it is unclear whether the have installed Hg-specific controls. An states that EPRI notes that these were standards are in fact more stringent. In analysis of the Hg content of the fuel design targets and were not to be used any case, CAA section 112(d) does not used during the 2010 ICR testing for permitting values. Commenters mandate that federal standards be more suggests that control in the range of 80 assert that the EPA has simply not stringent than state requirements for to 90 percent (fuel to stack) would be justified its process for going beyond- HAP emissions. Furthermore, states are needed to meet the beyond-the-floor the-floor for new IGCC units and that, authorized to establish standards more limit of 4.0 lb/TBtu. One low rank virgin without sufficient justification, the EPA stringent than this final NESHAP so coal-fired EGU achieved 75 percent actions are unsupported. promulgation of this rule will in no way control with no Hg-specific control Two commenters provided permit affect a source’s responsibility to technology (e.g., ACI). information, based on IGCC units comply with an otherwise applicable The EPA believes that its beyond-the- currently under construction, for PM state Hg or other HAP standard. floor analysis is appropriate, including and Hg emissions. One commenter the costs analyzed. The EPA’s cost requested that the proposed new MACT 9. Beyond-the-Floor analysis is meant to serve as an average floor limit for PM be modified to Comment: Several commenters stated for all sources in the subcategory address the two scenarios for duct that the proposed beyond-the-floor Hg recognizing that some EGU’s costs will burners at IGCC plants, syngas-fired and limit for low rank coal EGUs is based on be more and some less; EGUs whose natural-gas-fired. The commenter too little data and is technically and costs are higher are not exempted from requested the 0.050 lb/MWh limit be economically unattainable, noting that the regulation. Further, five EGUs in the increased to at least 0.068 lb/MWh

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based on gross energy output from the believes that the resulting Hg emission operate for only a small percentage of combined cycle generating unit when limit for a state-or-the-art IGCC unit hours during a year; and the need for a operated with duct burners fired with would be 0.003 lb/GWh, which is much non-continental liquid oil subcategory syngas. The 0.068 lb/MWh value is less than the Hg emissions for EGUs that for island units that have limited fuel consistent with the calculated emission directly burn coal. options and other unique ceiling for its permit to construct for this The commenter notes that IGCC units circumstances. The comments and the operating scenario. According to the are still in their infancy. Funding for EPA responses are provided below. commenter, there is not sufficient them will be very difficult or In general, the EPA has reviewed the experience with syngas turbines for unavailable if there is a regulatory limit data provided and continues to believe manufacturers to guarantee performance below the level that can be supported by that the coal-fired EGU subcategories in the 0.050 lb/MWh range. The vendor guarantees. Given the important proposed are the only ones supported 0.0681b/MWh performance basis role that IGCC units may have in by the data, though we have revised the proposed by the commenter was meeting global energy and climate basis for EGUs designed to burn low calculated based on the emission stability goals, the commenter believes rank virgin coal as discussed above. The guarantees that the commenter was able it would be a mistake to erect barriers EPA may not subcategorize by air to obtain for a turbine fired on the to the implementation of this pollution control technology type as syngas. The commenter also requested technology. The commenter stated that requested by a few commenters. that the 0.050 lb/MWh limit be the EPA can reevaluate the appropriate Further, the EPA has reviewed the other increased to 0.083 lb/MWh based on levels for future IGCC units after suggested coal-fired subcategories and gross energy output from the combined demonstration units which incorporate finds no basis for further cycle unit when operated with duct effective controls have been built and subcategorization (e.g., based on boiler burners fired by natural gas. The tested. design, boiler size, or duty cycle). Response: The EPA is not finalizing commenter indicated that, depending 1. Coal Subcategories on market conditions, the syngas the proposed new source standards for Comment: Commenters noted that produced at an IGCC may have more IGCC units. As commenters noted, EPA although other subcategories had been value as a raw material for producing proposed beyond-the-floor limits for evaluated, including subcategorization co-products than it would have as duct IGCC units based on the performance of of other coal ranks, no other coal rank burner fuel. Where that is the case, the PC-fired EGUs and solicited data from subcategorization was proposed. economic viability of an IGCC would be IGCC units that would represent what a Commenters submit there should be enhanced by firing the duct burners on new IGCC could achieve. We received subcategories for the coal ranks of natural gas and diverting that syngas to information that there are new IGCC units permitted and under construction. bituminous, subbituminous, and lignite. manufacture of a co-product. The The EPA believes one IGCC unit under The commenters noted that such commenter’s air permits are currently construction for which permit data were treatment would be consistent with past based on the use of syngas as duct provided is representative of both practice (e.g., CAMR where the burner fuel; however, the commenter is current technologies and of IGCC units differences in the type of emissions of currently examining an alternative that will be built in the near-term future. Hg due to the different chemical operating scenario that may result in Therefore, the EPA believes these properties of coal within differing fuel amendments to the air permits to permit levels should be the basis of the ranks was discussed). Commenters note authorize firing natural gas in the duct new source IGCC emission limits and that activated carbon has been shown to burners. Commenter states that the Agency is finalizing the PM and Hg be very effective when used in preliminary calculations indicate that limits on that basis, as that source will combination with low chlorine coals the PM limit would need to be set at be required to comply with its permitted (such as western subbituminous coals); 0.083 lb/MWh gross energy output limits once constructed and it is a however, activated carbons can suffer when operated with duct burners fired similar source. However, permit limits from poor performance when used with with natural gas. were only provided for PM and Hg; high sulfur coals. Commenters indicate The commenter also noted that there therefore, the EPA is finalizing the new that firing high sulfur coals (especially is not sufficient test data to precisely source limits for acid gas HAP based on when an SCR is also used) can result in predict the Hg emissions performance of data from the best-performing of the sulfur trioxide (SO3) vapor in the flue even the best-controlled IGCC units, existing IGCC units for the respective gas stream. The SO3 competes with Hg other than that IGCC Hg emissions are HAP. for binding sites on the surface of the expected to be much less than those for activated carbon (or unburned carbon) EGUs that directly burn coal. In its B. Rationale for Subcategories and limits the effectiveness of the permit application, the commenter Many commenters stated that the EPA injected activated carbon. But another proposed to establish a new standard for should have proposed more commenter noted that an SO3 mitigation Hg removal in IGCC units by treating the subcategories, while others believed that technology, such as dry sorbent syngas in catalytic reactors. The too many subcategories were proposed. injection (DSI, e.g., trona or hydrated catalytic reactor system is expected to Many different issues were raised by lime), applied upstream of the ACI can achieve greater than 95 percent Hg commenters, and some of the key issues minimize this effect. removal using either sulfur-impregnated that were considered in the final rule Commenters also stated that without activated carbon or alumina catalyst. In (some of which led to changes in the further subcategorization the economic the absence of actual stack test data, the final rule) include: the technical impacts on individual Midwestern commenter has had to estimate expected deficiencies in the definition for the states will be particularly acute as huge emissions based on engineering low-Btu coal subcategory; additional segments of the U.S. coal reserve will be estimates of how much Hg may arrive in subcategorization of the coal-fired EGU disenfranchised by this rule. According the syngas routed to the catalytic population; the need for to the commenters, the EPA did not reactors. Based on these engineering subcategorization of distillate vs. even attempt to legitimately analyze this estimates and 95 percent Hg removal in residual oil-fired EGUS; the need for a issue and, thus, in their opinion the the catalytic reactors, the commenter limited-use subcategory for EGUs that Agency’s proffered rationale for

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declining to further subcategorize based that activated carbon was only a all sources can comply with final on the acid gas standard is belied by the fledgling and unproven technology at standards without any action. record. The commenters believe that the the time; today, however, activated The EPA agrees, in theory, that EGUs EPA needs to better align this rule with carbon has been proven, and units are designed around a basic set of coal its previous position in CAMR and burning bituminous and subbituminous characteristics. However, the 1999 ICR further subcategorize based on coal coal can achieve the same levels of demonstrated that numerous EGUs have type. emissions for Hg and other HAP. conducted trial burns and gained Other commenters are opposed to any Consequently, the commenter believes sufficient experience such that co-firing further subcategorization based on coal the prior basis for subcategorization no blends of various coal ranks is now rank. Because many sources blend longer exists and the commenter, common practice. In fact, the EPA several ranks of coal on a regular basis, therefore, agrees that coal-fired EGUs believes that such blends may be commenters believe that establishing burning bituminous and subbituminous modified daily, depending on the coal rank subcategories would create coals ought to be grouped in a single characteristics of the coal being burned numerous opportunities for sources to category. and on the level of generation needed. game the regulations and substantially Response: The EPA disagrees with The extent of blending, and the ability increase emissions. Commenters stated commenters that additional coal-fired to switch the blends on short notice, that there is no need for such an subcategories are warranted and has not does not lend itself (or, in fact, argue approach since modern pollution provided any in the final rule. for) additional subcategorization. controls can accommodate a wide range Commenters are correct that additional The EPA disagrees with any assertion of coals. These commenters believe that subcategorization was proposed in that the EPA ignored possible EGUs firing different ranks of coal are January 2004. Whether or not such subcategorization approaches or that it not fundamentally different in size, subcategorization was warranted at that has insufficient data upon which to base class, or type in a way that impacts time, the EPA believes that the current or evaluate various subcategories. The emissions or that limits the availability conditions are such that, even if EPA fully examined the record, which of controls. The commenters believe appropriate at that time, such further demonstrates that coal-fired EGUs, with that emissions of fuel-dependent HAP subcategorization is not appropriate at the exception of certain units for Hg, can be controlled by either changing the this time. have similar HAP emissions profiles fuel prior to combustion or by removing When all of the factors noted by and that similar control approaches are the HAP from the flue gas after commenters have been reviewed, with available to such EGUs. Although combustion. Commenters state that ACI the exception of Hg for certain units, as commenters suggested additional systems, DSI controls, and PM controls discussed above, the EPA does not subcategories were warranted, they are available for installation at units believe that the HAP emissions to the failed to provide sufficient data to firing sub-bituminous coal and are atmosphere are sufficiently different support their proposed alternative equally available for units firing from coal-fired EGUs to warrant further subcategories. As noted elsewhere, the bituminous, anthracite, or lignite coal. subcategorization. There are EGUs firing EPA does not disagree with commenters These commenters also believe that as bituminous, subbituminous, and coal that there are some differences in EGUs. long as a control option is commercially refuse among the top performing units However, the EPA does disagree with available, the cost for a particular EGU for Hg and EGUs firing bituminous, commenters that those differences result is irrelevant to the EPA’s development subbituminous, lignite, and coal refuse in differences in emissions to the of emission standards based on MACT. are all among the top performers for the atmosphere such that additional Commenters stated that subcategories acid gas HAP and non-mercury metallic subcategorization is justified. based on coal rank would make a HAP indicating that the MACT floor Failing to demonstrate that coal-fired meaningful consideration of fuel limits established based on these units EGUs are different based on emissions, switching impossible, contrary to the are achievable by units burning all ranks the commenters turn to economic judicial mandate to consider of coal. arguments, asserting that failing to substitution of materials in setting the As noted by commenters, ACI, not subcategorize will impose an economic floor and the statutory mandate to fully developed in 2004, is now able to hardship on certain sources. Congress consider substitution of materials in the effect Hg control levels on precluded consideration of costs in beyond-the-floor analysis. subbituminous coals such that similar setting MACT floors, and it is not One commenter stated that although emissions to the atmosphere may be appropriate to premise they previously supported the achieved as those achieved by higher- subcategorization on costs either. See S. subcategorization of coal-fired units on chlorine bituminous coals when FGD Rep No. 101–228 at 166–67 (5 the basis of coal rank, they no longer systems are used or by coal refuse EGU Legislative History at 8506–07) object to grouping units that burn with less controls. Thus, in looking at (rejecting the implication that separate bituminous and subbituminous coals in the total system, similar emissions to categories could be based on ‘‘assertions a single category because the prior basis the atmosphere are achieved by all of of extraordinary economic effects’’); see for subcategorization no longer exists. these coal ranks. The EPA has addressed also NRDC v. EPA 489 F.3d 1364 (D.C. The commenter indicated that at the elsewhere in this document its rationale Cir. 2007) (holding that EPA properly time of CAMR, it was widely recognized for not subcategorizing by coal chlorine declined to create a subcategory for a that although coal-fired units content. The EPA does not believe that particular source and rejecting the combusting bituminous coal, with its any fundamental discrimination argument that the source may have to higher concentration of chlorine and, between coal ranks will occur as a result incur more costs to comply with the therefore, ionic Hg, could effectively of the final rule, though clearly some rule without such subcategory). limit Hg emissions by utilizing existing sources will be required to install The final limits are based on EGUs control technologies such as scrubbers, greater controls to comply with the final currently operating with available units burning subbituminous coal could standard. We maintain that such result controls. As noted above, the record not do so with the same controls is consistent with the intent of CAA shows that the various types of EGUs because of the coal’s higher levels of section 112 standards, which are not are represented in the floors, with the elemental Hg. The commenter stated intended to have an outcome whereby exception of certain units for Hg, which

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indicates that the levels are achievable upon to support a Hg subcategory for and cost saving measure to EGUs with by such units. Thus, the data actually low rank virgin coal. According to the installed FGD systems because we show that the MACT standards are commenter, the EPA’s key rationale for recognize that many EGUs have SO2 achievable for a wide variety of EGUs. a Hg subcategory for low rank virgin CEMS. Sources are required to comply In addition, the EPA believes it has coal was that no low rank virgin coal- with the HCl limit as a surrogate for all fulfilled the CAA section 112(c)(l) fired unit appeared in the ‘‘top the acid gas HAP or the SO2 limit as an directive that ‘‘[t]o the extent performing 12 percent of sources, alternate equivalent standard. practicable, the categories and indicating a difference in the emissions Commenters have not demonstrated that subcategories listed under this for this HAP from these types of units.’’ they are unable to meet the HCl subsection shall be consistent * * *’’ The EPA did not establish other standard and our data show that the with those of CAA section 111, subcategories because ‘‘the data did not standard is achievable even for high notwithstanding commenters assertion show any difference in the level of HAP chlorine coals. to the contrary. The decision on emissions and, therefore, we have Comment: Several commenters whether to directly align CAA sections determined that it is not reasonable to supported the development of a separate 112 and 111 subcategories is establish separate emissions limits for subcategory for fluidized bed discretionary and EPA has reasonably other HAP.’’ The commenter indicated combustors (FBC) or circulating exercised its discretion in declining to that the EPA does not need emissions fluidized bed (CFB) EGUs. The create additional subcategories for coal- data to know that even well-controlled commenters encouraged the Agency to fired EGUs based on the record, with the units burning higher sulfur coals would consider subcategorization of FBC EGUs exception of certain sources for Hg. be unable to meet the alternative SO2 for Hg emissions noting that the Finally, the EPA disagrees with the emissions rate, and would therefore also industry has long contended that the commenters that suggest that EPA lacks not appear in the top 12 percent of design, construction, and operation of the legal authority to consider material performing units. FBCs are different than conventional inputs when considering subcategories. Response: The EPA disagrees with boilers and that FBCs employ We agree, however, that material inputs commenters that subcategories should fundamentally different processes than must be considered when establishing be established for high sulfur and high conventional PC-fired EGUs. The MACT standards for the subcategories chlorine coals. It appears from the selection of an FBC unit over a that are established. We also believe a comments that it is not in fact the conventional PC boiler is driven in large meaningful consideration of fuel chlorine content that is at issue but the part by fuel characteristics. The switching can occur even if sources are sulfur content of the coal. Commenters commenters assert that, as a result, the subcategorized based on fuel inputs state that they are unable to meet the emissions profile of FBC units generally because EPA considers fuels switching HCl limit, but they only provide differ from conventional PC boilers in evaluating potential beyond-the-floor information indicating it would be because FBC units more advantageously alternatives. difficult to meet the alternative combust waste coals, as well as coal Comment: One commenter stated that equivalent SO2 limit. In fact, our data blends with other carbonaceous the EPA should establish an existing show that coals with chloride contents material. The commenters stated that source acid-gas subcategory for high as high as 2,100 ppm (0.16 lb/MMBtu) the EPA did not discuss the design sulfur or high chlorine coals because the were burned by EGUs making up the differences between FBC units and PC same factors that the EPA relied on to MACT floor pool of sources for the final units in the preamble to this proposed support a low rank virgin coal HCl emission limit and that the best- rule unlike what the Agency did when subcategory for Hg are also present in performing unit was burning coal with it previously proposed Hg MACT limits the high sulfur or high chlorine coal a maximum chloride content of 1,200 in January 2004. Commenters state that, context. The commenter stated that the ppm. The median chloride level for for these reasons, FBC units can be data indicate that even well-controlled bituminous coals identified from data considered a distinct type of boiler. units burning high sulfur coals would submitted through the 1999 ICR was The commenters noted that an not be in the top performers for acid 1,030 ppm so we believe that the coals examination of the 40 ‘‘best performing’’ gases even at removal rates of 95 or 96 represented in the MACT floor pool units for Hg emissions in the proposed percent. The commenter added that indicate that the final limits are MACT floor spreadsheet showed that 14 absent such a subcategory, about 12 achievable with high-chlorine coals. We of those units are FBC units. The percent of coal deliveries (2005 data), have determined that HCl removal is commenters maintained that had FBC and the vast majority of coal shipped very effective using a number of units performed as well as conventional from the states of Indiana, Ohio, and different types of FGD systems. Absent PC boilers, 2 units would have been Illinois (2008 data), would become information demonstrating that sources expected to be in the top 40. The unusable. The commenter expressed are unable to meet the proposed HCl commenters allege that the far higher support for the alternative SO2 standard limit due to the chlorine content of the percentage of FBCs in the top 40 leads for units unable to meet the HCl coal, we believe it is unnecessary and to the conclusion that these units are standard; however, the commenter also inappropriate to consider different from conventional PCs with believed that it is appropriate to subcategorizing based on chlorine regard to Hg emissions and, as a result, establish a coal chlorine or sulfur content in the coal. should have been placed in their own content-based subcategory for the In addition, as noted above, the SO2 subcategory. Further, commenters noted alternative SO2 standard. The limit is an alternative equivalent that the largest FBC has a nameplate commenter stated that coal testing data standard that is available to sources that capacity of about 300 MW while the indicate a clear break in chlorine have an SO2 control and CEMS and largest conventional boilers have concentrations in the coals burned by operate the controls at all times. The nameplate capacities of around 1,300 EGUs, as well as in sulfur content. The EPA did not provide the alternative MW. commenter indicated that there are equivalent standard for sources that The commenters stated that FBCs factors supporting a high sulfur or high could not meet the HCl limit as one combust relatively large coal particles in chlorine coal subcategory that are commenter suggests; instead, we a bed of sorbent or inert material at a similar to those that the EPA relied provided the standard as a convenience lower degree of combustion efficiency.

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Fluidized bed units operate at less than being that they were selected to test in an exception and such EGUs are found half of the temperature of a the 2010 ICR because of their boiler across the range of top performing EGUs conventional boiler and have much design. However, FBC EGUs were not for all of the HAP categories: Acid gas, longer fuel residence times. specifically selected as best performers non-mercury metallic, and Hg. In Conventional boilers pulverize coal to a for Hg, as EPA did not select any EGUs addition, any assertion that non-FBC very fine particle size to maximize based on a determination that they were EGUs are unable to meet the final combustion efficiency and minimize best performers for Hg (as noted standards because FBC EGUs are unburned carbon. As a result, the elsewhere, we had no basis for selecting included in the same subcategory (or commenters noted that FBCs typically EGUs as being best performers for Hg), vice versa) is plainly refuted by the fact have higher levels of unburned carbon and to the extent CFB units were that EGUs of all types are currently present in the ash, which behaves much selected in the 2010 ICR, they were meeting one or more of the final like activated carbon and helps promote selected because we determined they standards. Thus, the EPA finds no basis more efficient Hg removal. Accordingly, were best performers for non-mercury for subcategorizing FBC EGUs. commenters maintain that Hg emissions metallic HAP, acid gas HAP, or organic Further, as noted below, the EPA does of FBC boilers and PC boilers are HAP or because they were randomly not believe there is a basis for statistically different, with emissions selected among the non-best performers subcategorizing small EGUs, either FBC from FBCs significantly lower than for those three HAP groupings. Thus, or PC. In addition, the data have been those from PC boilers. According to the CFBs were selected for testing under re-evaluated based on comments commenters, this statistically significant the 2010 ICR based not on their boiler received and an FBC unit is not the difference in the Hg emissions profiles design but, rather, based on the age and basis for the new source Hg MACT floor. for these two distinct boiler on their PM and FGD control systems Comment: Many commenters stated technologies argues in favor of the (as noted in the Supporting Statement that the EPA should have considered creation of a separate subcategory for for the 2010 ICR). As many FBC EGUs, additional subcategorization schemes, FBCs, as there is no control technology including CFB EGUs, are relatively new, including one based on EGU size. that PCs could install that would result they were included in the non-mercury Commenters noted that one of the in emissions reductions similar to those metallic HAP group selected for testing factors that the Administrator can achieved by FBCs. The active quantity (because their PM controls were among consider under CAA section 112(d)(1) in of calcium oxide (lime-CaO) available in the 175 newest), the acid gas HAP group making subcategorization decisions is a FBC boiler is also orders-of-magnitude selected for testing (because FBC was unit size. Commenters stated that an greater than compared to a PC boiler, considered to be an FGD system and the analysis of the 2010 ICR data showed a whose alkalinity is derived solely from units were among the 175 newest), and statistical difference between EGUs with the coal’s mineral content. Significantly organic HAP testing (because they were a capacity of 100 MW or less and EGUs higher CaO can alter the process among the newest and, thus, determined above 100 MW; other commenters chemistry in the boiler, including the to be among the most efficient). suggested that the cut-off range should oxidation levels of Hg. The effect on Hg emissions is not be 125 MW. Although large in number One commenter stated that the EPA what commenters suggest because, (about 27 percent) of all EGUs, these properly declined to subcategorize units although, as noted by commenters, FBC small EGUs only comprise about 5 based on design type where there is no units may be found among the better percent of the coal-fired capacity in the indication that any physical distinctions performers (among the top 10 EGUs) on U.S. Thus, commenters assert that if among unit designs have a meaningful the Hg MACT floor spreadsheet, they different MACT limits are set for this and substantial impact on HAP are also found in the range of 221 to 226 subcategory of EGUs, it will not have a emissions. The commenter indicated EGUs (of 393 data points). The fact that significant impact on the health effects that it would be inappropriate to FBC units have ‘‘vastly dissimilar ash of HAP emissions. Commenters noted subcategorize FBCs because there is no properties’’ that may contain higher that although emission rates from such evidence to support a determination levels of lime or unburned carbon in the small EGUs are greater than those found that FBC design is responsible for a unit fly ash than conventional PC EGUs does in the large unit fleet, their contribution falling in or out of the top 12 percent for not indicate that the overall system to the total EGU emissions is not a particular HAP. behaves any differently with regard to significant. The costs associated with Response: The EPA acknowledges emissions to the atmosphere (the key coming into compliance with the that there are design and operation metric) than a conventional PC EGU proposed rule by installing new controls differences between conventional PC- with add-on controls. The asserted would be proportionally much higher fired EGUs and FBC/CFB EGUS; higher levels of unburned carbon result for these small EGUs than larger EGUs however, the commenters are incorrect in a range of effectiveness of Hg control according to the commenters. The in asserting that the HAP emissions that is similar to that of ACI found on commenters allege that this would force levels and characteristics are PC EGUs; such ACI control may be the retirement of generation capacity sufficiently distinct from other coal- found on EGUs that are among the better and threaten electrical reliability fired EGUs to support subcategorization. performers as well as on EGUs as low without appreciable benefit to the Further, commenters fail to note that as 369 on the list of data points. Thus, environment. FBC EGUs were not subcategorized in the EPA disagrees that FBC units are One commenter stated that in general, CAMR even though, as commenters disproportionately represented in the the nature of many public power note, such design and operation Hg floor and that their inclusion is facilities differs from the general differences were cited there. The fact somehow inappropriate or leads to population of coal-fired power plants. that FBC units operate at lower skewing of the analysis. Public power units tend to be smaller in temperatures is of no consequence as All types of coal-fired EGUs other size, and are often space-constrained by they still operate at temperatures high than those we subcategorized are growth in the community surrounding enough to vaporize Hg. represented in the MACT floors for Hg the generating unit since its initial Commenters assert that FBC units are and all types of EGUs are represented in construction. These limitations restrict disproportionately represented among the floors for the non-mercury HAP. the ability of these EGUs to achieve the the best performers, with the inference Fluidized bed combustion EGUs are not same performance levels of larger,

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unconstrained EGUs; and, for those between a 500 MW EGU and a 1,300 would decline to include such a EGUs that can comply with the MW EGU and reaffirm our position that subcategory. proposed standards, the installation of the MW capacity of the EGU is not a Therefore, given the language of CAA controls sharply increases the cost of determining factor in its emissions. section 112(d), the legislative history, compliance. The commenter stated that Further, the EPA believes that units of and the available information, EPA is the EPA did not adequately all sizes are owned by both large and not creating a separate subcategory for subcategorize to accommodate many small entities. EGUs owned by small entities. small- and medium-sized public power The EPA examined the effect if EGUs In addition, the D.C. Circuit has utilities. In particular, the EPA did not less than 125 MW were subcategorized clearly stated that the EPA does not avail itself of the opportunity to use a for Hg. The resultant MACT floor for have the statutory authority under CAA public power electric utility these EGUs would be 1.0 lb/TBtu on a section 112 to extend compliance dates subcategory, rural subcategory, or fuel 30-boiler operating day rolling average, past the 3-year maximum compliance type subcategories. Other commenters a level more stringent than that time authorized in CAA section endorsed the establishment of a less developed for the >8,300 Btu 112(i)(3)(A) except consistent with CAA than 100 MW subcategory that would subcategory as a whole. We do not sections 112(i)(3)(B) and 112(i)(4). See reduce the costs of the proposed rule believe that this is what commenters NRDC v. EPA, 489 F.3d 1364, 1374 (D.C. significantly, but only affect 5 percent of envisioned when suggesting such a Cir. 2007) (finding that ‘‘Congress the total electric utility sector, and help subcategory but we believe it confirms enumerated specific exceptions to the 3- minimize retirement of uneconomical our analysis of the data that indicates, year maximum, which indicates that plants. as noted, these units are controlled in Congress has spoken on the question One commenter stated that the EPA the same manner as other, larger EGUs, and has not provided the EPA with properly recognized that subcategories such that additional subcategorization is authority under subsection 112(i)(3)(B) based on unit size would be not necessary or reasonable. Further, to extend the compliance date * * *’’) inappropriate because the proposed based on the number of EGUs less than (citing also CAA section 112(i)(4)). The EPA may not alter the compliance date emission limits are in terms of lb/ 125 MW in the HCl and PM MACT floor based on size or ownership MMBtu or lb/TBtu and noting that an pools, we believe that a similar analysis considerations and, thus, we are not EGU’s total nameplate capacity is for HCl and PM would lead to similar providing a separate compliance date wholly unrelated to its ability to achieve or more stringent standards than for different groups of EGUs in the final the proposed limits. Another without the additional subcategory. rule. commenter opposed any proposal to Thus, units of all sizes are capable of subcategorize units below 100 MW. The Comment: One commenter stated that achieving the proposed limits and the the EPA should establish a subcategory proposed rule does not apply to units EPA is not finalizing a subcategory less than or equal to 25 MW, and this consisting of EGUs that had received air based on unit size in the final rule. commenter believed that this is a construction permits but had not yet The CAA authorizes EPA to sufficient threshold for applicability. commenced construction as of the date One commenter stated that the EPA subcategorize based on ‘‘classes, types, of the EPA’s proposed rule. The could establish subcategories for the and sizes of sources.’’ The EPA does not commenter believed that such a purpose of temporarily exempting, for believe that this provision permits category would be justified because a example, a subcategory of utilities that subcategorizing sources based solely on substantial amount of time, money, and meet the definition of small entity for their status as small entities for several effort has been invested in these units. purposes of the proposed rule. The reasons. As a threshold matter, The commenter asserted that imposing temporary exemption would sunset on a commenters provided no information to new source standards on these EGUs for date certain (e.g., 3 years from the suggest that EGUs at small entities are which the EPA’s proposed rule had not effective date of the rule) at which point different from EGUs owned by other been anticipated during their permit the sources in the subcategory would entities. Instead, the commenters’ consideration would unreasonably and become subject to the rule, and a justification for such a subcategory was arbitrarily impose additional costs and compliance timetable would start to that the costs to comply with the burdens on these projects and would run. The commenter believed that this standards make it more difficult for likely threaten the viability of many of time-staged promulgation and small entities; thus, the basis is them. The standards for this subcategory compliance proposal would greatly essentially a cost basis and we do not would be based on the anticipated increase the chance that the control think that is consistent with the statute. performance of these units (as reflected measures could be added in an orderly Moreover, the legislative history of CAA by the permitted case-by-case emission and efficient manner with minimal section 112(d) supports EPA’s levels), ensuring a reasonable and disruption to power markets and grid interpretation that subcategories cannot appropriate level of HAP control reliability. be based on the cost of compliance. See without unreasonably and arbitrarily Response: The EPA agrees with S. Rep No. 101–228 at 166–67 (5 interfering with the development of commenters who stated that an EGU’s Legislative History at 8506–07) these units. size is totally unrelated to its ability to (rejecting the implication that separate Response: Clean Air Act section comply with the final concentration- categories could be based on ‘‘assertions 112(a)(4) defines a new source as ‘‘a based limits. The EPA examined the of extraordinary economic effects’’). stationary source the construction or size of units within the respective In addition, the EGUs owned by small reconstruction of which is commenced MACT floor pools of sources and found entities use the same type of fuel as after the Administrator first proposes units ranging in size from 25 to 1,320 other units, have the same type of regulations under this section MW in the HCl floor pool, from 25 to combustor designs, and can use the establishing an emission standard 869 MW in the non-mercury metallic same types of controls, and so there is applicable to such source.’’ The EPA’s floor pool, and from 47 to 544 MW in no difference in the HAP emissions regulations implementing the CAA the Hg floor pool. Thus, we find no from such units. So, even if we believed section 112 General Provisions define more difference between a 25 MW EGU a subcategory based on small entities ‘‘commenced’’ to mean ‘‘with respect to and (e.g.) a 500 MW EGU than we do was consistent with the statute, we construction or reconstruction of an

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affected source, that an owner or Nation and the U.S. government, and low sulfur diesel (ULSD) oil, has fuel operator has undertaken a continuous consistent with the right of sovereignty characteristics closer to that of pipeline program of construction or and self-determination of the Navajo gas than to residual oils. The metals, as reconstruction or that an owner or Nation, it may be appropriate to classify well as the ash and nitrogen content, of operator has entered into a contractual EGUs on tribal lands in a different distillate oils are very low, and the obligation to undertake and complete, subcategory from those on non-Indian sulfur content of ULSD is approximately within a reasonable time, a continuous lands. The commenter stated that in the same as that of pipeline natural gas. program of construction or accordance with the distinctive status of The commenters state that distillate oil reconstruction.’’ See 40 CFR 63.2. Indian lands, based on principles of is a more refined product than residual The EPA is constrained by the tribal sovereignty and self- oil and, thus, burns cleaner. According definition of ‘‘new source’’ such that determination, the government-to- to commenters, separating liquid oil- any source that ‘‘commenced’’ government relationship, and the fired EGUs into two subcategories construction after the May 3, 2011, flexibility of federal agencies mandated (distillate and residual oil) would be proposal date is considered a new under E.O. 13175, the EPA should consistent with the discussion of source under the statute and the source classify sources on tribal lands as a subcategory differentiation in the rule’s must comply with the new source unique subcategory of EGUs for which preamble which indicates that the standards even if the source received a emission standards for NESHAP should division of a category into subcategories final and legally effective CAA section be set pursuant to CAA section is justified if the two subcategories have 112(g) permit before proposal. It is 112(d)(3). very different emissions, which is true unclear from the comments whether the Response: Pursuant to CAA section for distillate vs. residual oils. Distillate sources identified in the comments have 112(d)(1), the EPA may subcategorize and residual oils are also differentiated commenced construction as defined in sources based on differences in class, by their operating requirements. Some the regulations; however, the identified type, or size. In the preamble to the commenters stated that as a sources are existing sources, not new proposed rule, the EPA further explains consequence of the mechanical sources, under the final rule if that any basis for subcategorizing (e.g., differences between boilers designed for construction was commenced prior to class) must be related to an effect on residual oil vs. distillate oils, and the proposal date. emissions, rather than some difference between the fuel-handling requirements Under the final rule, new sources which does not affect emissions for the different fuels, it is not possible must comply with the standards on the performance. The EPA does not agree to interchange oil types without date of promulgation or at startup, that a subcategory based on location on significant modifications to the oil whichever is earlier, and existing Tribal lands is consistent with the storage tanks, transfer pumps, piping sources have 3 years to come into statutory authority to subcategorize, and and valves, flow control systems, compliance with the final standards. commenters do not explain why burners, and burner control systems. Pursuant to the EPA’s regulations at 40 emissions would be different for EGUs Commenters also noted that some of the CFR 63.44(b)(1), however, we may located on Tribal lands. Absent that EGUs in the EPA’s liquid oil-fired provide in a final CAA section 112(d) showing, EPA believes it would not be database were mischaracterized with standard a specific compliance date for appropriate to subcategorize units even regard to the type of oil burned during those sources that obtained a final and if we believed such a subcategory is the 2010 ICR testing. legally effective CAA section 112(g) consistent with the statute. CAA section Some commenters alleged that by case-by-case MACT standard and 112 imposes specific requirements with combining distillate and residual oil submitted the information required by respect to the methodology that the EPA into a single MACT category, the 40 CFR 63.43 to the Agency before the must use in establishing emission resultant MACT standards cannot be close of the comment period. The EPA standards for HAP, including Hg satisfied by a boiler firing residual oil does not believe it has received such emissions from EGUs. Pursuant to CAA without substantial add-on controls. information during the comment period section 112(d)(1), the EPA may The commenters asserted that creation and we are not establishing a separate subcategorize sources based on of separate subcategories for liquid oil- specific compliance period for sources differences in class, type, or size. The fired units that distinguish between that obtained final and legally effective EPA believes, that any basis for residual and distilled oil would render CAA section 112(g) standards prior to subcategorizing (e.g., class) must be the standards more achievable for promulgation of the final rule. In the related to an effect on emissions, rather distinct subcategories of EGUs and absence of EPA action on this issue, than some difference which does not reduce the number of potential plant state Title V permitting authorities are affect emissions performance. closures while still advancing the goal required to ‘‘establish a compliance date However, the EPA is sensitive to the of reducing overall emissions. These in the [title V] permit that assures that commenters’ concerns and particularly commenters contend that MACT floors the owner or operator shall comply with recognizes the significance of Navajo should not be used to eliminate whole the promulgated standard [ ] as Generating Station to the Central classes of existing EGUs through expeditiously as practicable, but not Arizona Project and the water delivery mathematical floor calculations based longer than 8 years after such standard to tribes. As a result, EPA has been on data from uncontrolled units and is promulgated * * *’’ 40 CFR consulting with affected Indian tribes combining boiler subcategories that are 63.44(b)(2). Sources with final and and working closely with other federal not capable of accommodating a legally effective section 112(g) standards agencies, including the Department of different fuel. should work with their permitting the Interior, on these issues and intends One commenter stated that the EPA authorities to determine the appropriate to work with tribal and other authorities should not subcategorize liquid oil-fired compliance date consistent with the to ensure a smooth transition and EGUs based upon different grades of EPA regulations. address specific issues as they arise. liquid oil. Although different grades of Comment: One commenter stated that liquid oil may vary in their heat in accordance with CAA section 2. Oil Subcategories contents or viscosities, the commenter 112(d)(l), based on the government-to- Comment: Several commenters stated maintained that there is no indication in government relationship of the Navajo that distillate oil, and in particular ultra- the rulemaking record that any physical

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distinction among units burning residual oil, the users of distillate oil regimen, the commenter believed that it different grades of liquid oil affects the would have no means of compliance is essential that it be able to do so. nature or characteristics of emissions in other than obtaining ‘‘compliance’’ oil Other commenters noted that a way that impacts the availability of from their distributor (which was not requiring installation of emission controls. According to the commenter, indicated as an option by any controls on oil-fired units that operate at both distillate and residual oil-fired commenter) or converting to natural gas a 10 percent oil-fired capacity factor or units can apply similar control and being removed from the less is nonsensical and will result in technologies to reduce HAP emissions, subcategory. With no further little environmental benefit. and EGUs firing these fuels do not have subcategorization, oil-fired EGUs have Commenters contend that low-capacity physical distinctions that prevent the option of installing an ESP or factor units emit significantly less HAP controls from operating effectively. The converting to distillate oil for than even well-controlled oil-fired units commenter believes that fuel switching compliance. Commenters did not with much higher capacity factors. In is an appropriate control technology and contend that it was impossible to addition, commenters allege that stack- is available for liquid oil-fired sources. convert to distillate oil, only that it testing at such units would be equally Residual fuel oil contains higher levels would require plant modifications. impractical and, in addition, would of contaminants, including HAP, than Installing controls would also require likely require the unit to operate on oil distillate oil, and because a regulated plant modifications so sources will be (and emit HAP just for the test) when it entity can readily burn cleaner distillate able to evaluate the options and would otherwise be off-line or operating oil in lieu of residual oil, it is determine the most cost-effective option on natural gas. inappropriate to subcategorize based on to comply with the final rule. CAA Response: As stated above, after the distillation fraction of the liquid oil. section 112 is intended to be a considering comments received, we are Thus, according to the commenter, the technology-forcing statute, and, because establishing a limited-use subcategory grade of liquid-oil fuel does not provide both distillate oil- and residual oil-fired for liquid oil-fired EGUs with an annual a reasonable basis for subcategorizing EGUs were among the best performing fired capacity factor of less than 8 various groups of liquid oil-fired EGUs. sources in the floor and both types are percent averaged over each 24-month Another commenter alleges that the EPA meeting the final standards, we cannot block period after the compliance date. did not list distillate oil-fired EGUs in reasonably conclude that the HAP At proposal, we solicited comment on the 2000 Finding. emissions characteristics of these establishing a limited-use subcategory Response: The EPA has reviewed the similar types of units are distinct. for liquid oil-fired EGUs: data and determined that it is not Therefore, the EPA is not establishing EPA is also considering a limited-use necessary to subcategorize distillate vs. separate subcategories for distillate and subcategory to account for liquid oil-fired residual oil. Commenters had noted that residual oil-fired units in the final rule. units that only operate a limited amount of the EPA’s MACT Floor Analysis time per year on oil and are inoperative the spreadsheet at proposal had erroneously 3. Limited-Use Subcategory remainder of the year. Such units could have assigned the oil type used during testing specific emission limitations, reduced for some boilers. The EPA reviewed the Comment: Several commenters stated monitoring requirements (limited operation data and determined that the submitting that EPA should establish a limited-use may preclude the ability to conduct stack companies had entered the data subcategory for liquid oil-fired EGUs testing), or be held to the same emission incorrectly, or had indicated that two that are required to burn oil during limitations (which could be met through fuel types of oil were fired in different parts periods of natural gas curtailment. One sampling) as other liquid oil-fired units. EPA commenter stated that under New York solicits comment on all of these proposed of the 2010 ICR responses. The EPA subcategorization approaches. contacted all of the companies with oil- State Reliability Council Rules, their fired EGUs in the 2010 ICR to confirm facility is required by the New York As stated above, the EPA did not have the oil used during testing. Upon review Independent System Operator (NYISO), sufficient information on limited-use of these data, it became apparent that for reliability purposes, to maintain the liquid oil-fired EGUs upon which to units using residual oil with ESPs or capability to burn oil and actually burn base a subcategory at proposal. Some distillate oil without control were the oil, from time to time, at varying load sources required to test under the ICR best-performing oil-fired EGUs for PM levels to help avoid or avert potential did not submit the data until after and the HAP metals. Further, although natural gas shortages in New York City. proposal. Commenters indicated that emissions of HAP from distillate oil- The requirements to burn oil under this their units are different because many of fired EGUs are generally lower than program are mandatory and are not them are only called to service to those from residual oil-fired EGUs, within the commenter’s discretion. The address reliability issues associated EGUs burning distillate oil appeared to reliability rules require that the with, for example, natural gas have higher emissions of some HAP but commenter’s EGUs maintain their co- curtailments. The commenters further lower emissions of others. firing capability to respond to indicated that their units are different In addition, the EPA does not agree unplanned, emergency scenarios by because of the generally infrequent use that distillate oil-fired EGUs were not operating on oil during required and the sporadic, and at times frequent, listed in the 2000 Finding. We believe minimum oil burn periods, typically 25 start-up and shutdown periods (e.g., it is inappropriate to exclude distillate percent oil/75 percent natural gas. The they are often only required to run for oil-fired EGUs from regulation under the commenter noted that operation using a couple of hours). These factors would final rule because the Agency did not oil at other times or on 100 percent oil lead to differences in the emissions make a distinction when listing the oil- during reliability operation periods characteristics for these units such that fired units. occurs very infrequently; with natural a numeric standard based on base load The EPA also disagrees with gas expected to become more available units would not likely be achievable commenters that by providing the in future years, such an operating during the very limited times that these distillate vs. residual oil subcategories scenario will become less likely. limited use oil-fired units operate. as requested, the resultant standards However, while the reliability rules Based on comments received and our would be more achievable. Were the remain in place and commenter’s own analysis, we are finalizing a EPA to subcategorize distillate oil from boilers are required to operate under his subcategory for limited-use liquid oil-

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fired EGUs as indicated elsewhere in times they would not otherwise run, it 4. Non-Continental Units this preamble. We find that these units would result in both extra cost related Comment: Commenters from affected constitute a different class and type of to the testing as well as extra emissions; island EGUs requested that non- units because they are generally only therefore, the Agency believes that it is continental EGUs be subcategorized used to address reliability issues technically and economically from continental EGUs based on their associated with, for example, natural gas impracticable to monitor emissions for lack of access to natural gas. The curtailments, and because they in fact these EGUs, and that they should be commenters urged the EPA to include a only run for very limited periods in a subject to work practice standards that ‘‘non-continental liquid oil’’ year on a seasonal basis. would not require emissions subcategory in the final rule. According Although some commenters indicated monitoring. to the commenters, establishing a a prevalence of natural gas/oil co-fired The annual average capacity factor subcategory for non-continental units is EGUs, the EPA also understands that would be calculated on a 24-month consistent with the approach the EPA there are other liquid oil-fired EGUs that block period, commencing with the has taken in past rulemakings, including do not co-fire natural gas but that could compliance date of the final rule. For the final Industrial Boiler NESHAP. be subject to mandatory operation example, assuming a March 1, 2015, Non-continental EGUs have little or no during periods of natural gas compliance date, the first 24-month access to natural gas, minimal control curtailment in their operating area if block would commence on March 1, over the quality of available fuel, and sufficient non-natural gas capacity is not 2015, and end on February 28, 2017, disproportionately high operational and available. Based on a review of units with the next 24-month block averaging maintenance costs. All oil-fired EGUs that report oil use to EPA, in 2010 there period commencing on March 1, 2017. operating in Hawaii, Guam, and Puerto were 228 liquid oil-fired EGUs with a We believe the 24-month averaging Rico combust residual fuel oil capacity factor of less than 5 percent period is reasonable to account for the exclusively and all are limited by the and an additional 10 units with a fact that units needed to address crude slates of their fuel suppliers. capacity factor of between 5 percent and reliability issues (e.g., natural gas Island utilities can contract with 10 percent. Only 2 of these units have curtailment periods) will be called to suppliers for certain fuel specifications, capacity factors between 5 percent and service sporadically. A 24-month such as sulfur content, pour point, flash 8 percent. This subcategory applies only averaging period provides flexibility to point, API gravity and viscosity, which to oil-fired EGUs that operate on oil ensure that these units can run if there the refiners are able to meet primarily alone and act as peaking units, as they are large periods when natural gas is by blending and some sulfur removal generally address reliability issues. We unavailable. As explained above, the during the refining process. However, are establishing the capacity factor data shows that most of these units the commenters state that the suppliers threshold of 8 percent averaged over operate for less than 8 percent of the do not and cannot economically control each 24-month block period after the time, and in fact it is usually less than 320 for metal content. The crude slate compliance date. In addition, as 5 percent. Therefore, when considering feeding the refinery determines the HAP discussed below, we are establishing whether these units would be able to metal content of the residual oil work practice standard for this perform stack testing, in many cases this produced according to the commenters. subcategory in lieu of numeric emission will be for units that in fact operate Because island utilities are dependent standards. significantly less than 8 percent of the on local sources of fuel, they are equally Commenters that requested a time. In these cases, the EPA does not limited by these factors. subcategory for these units noted the want to require the units to operate Two commenters believe that the dichotomy of establishing a NESHAP to more just for the purpose of running a separate non-continental subcategory reduce emissions of HAP to the stack test resulting in additional should be expanded to include environment while at the same time pollution and cost. With projections for continental areas that are not requiring an EGU to run for the sole rising oil prices relative to natural gas interconnected with other utilities and purpose of conducting emissions testing prices, we expect this trend to continue. have limited compliance options due to and thereby emitting those same HAP. Liquid oil-fired EGUs subject to this remote locations (e.g., Alaska). Because the operation of these units is subcategory would be required to Response: The EPA agrees that the infrequent and unpredictable, conduct the same initial and periodic unique considerations faced by non- performing testing to demonstrate that tune-up as all other affected units, but continental EGUs warrant a separate emission limits are being met requires would have no other emission limit or subcategory for these units and the data the sources to be scheduled to be work practice requirements. show that the difference in location operated merely for the purpose of Although the EPA believes that the causes a difference in emissions performing testing. We realize that ability to burn oil up to 8 percent of the apparently due to the fuel that is similar situations occurred in the time should address concerns about available for such units; thus, the gathering of emissions data through the units that may need to operate using oil Agency has included such a subcategory 2010 ICR. However, unlike the case of during gas curtailments. The EPA in the final rule. At proposal, the EPA one-time testing on a limited number of recognizes that if there were a period did not have all of the data from liquid these units, such testing would be where gas use was more severely oil-fired units in non-continental areas mandatory on a yearly basis for all of limited, such units might need the (e.g., Guam, Puerto Rico) and solicited the EGUs upon the effective date of the flexibility to operate for more than 8 comment on whether a subcategory final rule. Because requiring testing percent in one year and less in the next, should be established, based on the data under this rule would in many cases which is why we are providing the 2- to be received, for non-continental oil- require operators of these EGUs to year period; however based on the data fired EGUs. The EPA has now received schedule operation of these EGUs at we do not think EGUs in this these late data and, based on those data, subcategory will exceed even the 5 is finalizing a non-continental 320 Units that co-fire oil and natural gas where the subcategory for liquid oil-fired EGUs in oil combustion comprises 10 percent or less of the percent capacity factor that the data capacity factor are natural gas-fired EGUs that are indicate is the average level for these Guam, Hawaii, Puerto Rico, and the U.S. not subject to this final rule. sources. Virgin Islands. The EPA is not aware of

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any liquid oil-fired EGUs in any of the we compared the correlations associated or HF measurements or by other U.S. territories that meet the CAA with non-mercury HAP metal emissions demonstrating that the moisture content section 112(a)(8) definition but, if there and the three forms of PM and found in the fuel oil remains at a level no more are such units, they would also be part that no specific particulate form than 1.0 percent. of the non-continental subcategory. provided a consistently superior The EPA is not aware of any FGD The EPA agrees that the unique indicator of better metals control. systems installed on oil-fired EGUs. considerations faced by non-continental Although control of filterable PM Thus, it is only the quality of the oil, refineries, including a limited ability to provided the best indicator of and the level of HAP constituents obtain alternative fuels that lead to performance for control of some HAP contained therein, that can be relied different emissions characteristics, metals, control of total particulate or upon for ensuring compliance. warrant a separate subcategory for these total PM2.5 was nearly as good as an In the proposal preamble, we stated: EGUs. The EPA believes that units in indicator. For control of other HAP We believe that chlorine may not be a this subcategory will comply through metals, total PM measurement provided compound generally expected to be present the use of cleaner oils or, for PM, the best indicator of control in oil. The ICR data that we have received through the installation of an ESP. The performance because it included the suggests that in at least some oil, it is in fact EPA finds no merit in the comment that vapor-phase metal HAP, although, present. EPA requests comment on whether Alaska should be included in this non- measurement of the control of filterable chlorine would be expected to be a continental subcategory because utilities particulate was nearly as good an contaminant in oil and if not, why it is appearing in the ICR data. To the extent it in Alaska are not faced with the same indicator. In addition, certain data analyzed by our Office of Research and would not be expected, we are taking access issues affecting island-based comment on the appropriateness of an HCl facilities. Development indicate that a vapor- limit. See 76 FR 25045. phase metal, such as Se, can be present C. Surrogacy as an acid gas and reduced significantly Commenters refer to certain studies that provide a plausible reason for the 1. Filterable PM vs. Total PM using acid gas technologies (wet and dry scrubbing). Given that the rule also chloride/fluoride contamination of fuel Comment: Numerous commenters provides for acid gas control oils. We found this reason persuasive strongly objected to the use of total PM monitoring, and the general equivalency and accordingly are providing as the surrogate standard for non- of the different indicators, we have alternative compliance approaches in mercury HAP metals. They argued that concluded that use of a filterable PM the final rule to demonstrate compliance filterable PM is a better surrogate, limit as the PM surrogate emission limit with the acid gas HAP standards. especially given EPA’s intent to use a is appropriate. Specifically, sources can demonstrate PM CEMS for continuous compliance compliance through either specific HCl demonstration. Other commenters 2. Moisture Content of Oil or HF measurements or by argued that we should not use a Comment: A number of commenters demonstrating that the moisture content surrogate and instead should require stated that studies suggest that chloride in the fuel oil remains at a level no more direct compliance with a non-mercury in fuel oil can result from contamination than 1.0 percent. HAP metals standard. during transportation and processing of D. Area Sources Response: We have decided to use a crude oils and then be emitted as HCl filterable PM limit for the PM surrogate during combustion. For example, the Comment: Numerous comments were emission limit in the final rule. commenters asserted that the chloride received both in support of and in Although the objective of the contamination of crude oils can occur as opposition to the establishment of emission limits we are establishing is to a result of the ballasting of tanker ships generally available control technology reduce the risks associated with HAP with seawater. However, the Oil (GACT) standards for area source EGUs. emissions, the limits are based in part Pollution Act of 1990 requires all new Several commenters in opposition to upon the demonstrated capabilities of oil tankers to be double hulled and area source standards stated that the control technologies which are installed establishes a phase out schedule (by the EPA properly established emissions on existing sources. Except for Hg, the middle of the decade) for existing single limitations based upon the performance best PM controls provide the best hulled tankers with un-segregated of all EGUs, rather than distinguishing controls of metal emissions. Emissions ballasts. Because of the role of seawater between major sources and area sources. measurements of either filterable contamination in introducing The commenters believe that Congress particulate, total particulate, individual contaminants into the oil, the did not intend the EPA to distinguish metals, or total metals provide commenters suggest that the EPA set a between ‘‘major source’’ EGUs and ‘‘area comparable indications that the best percent water content limit for fuel oil source’’ EGUs in determining whether level of control is achieved. We can find at a level of 1.0 percent, rather than and how to regulate EGUs under CAA no significant difference in the setting HCl and HF emissions limits. section 112. These commenters emissions that would be achieved by This would encourage handling and indicated that differentiating major using any one of these emissions transport practices to limit salt water source and area source EGUs for measurements. contamination. One commenter purposes of setting emissions standards We re-assessed the relationships recommended a standard of 1.0 percent is inappropriate in light of the 2000 between individual metal emissions, water because several of the lowest HCl Finding regarding the threat posed by filterable PM emissions, total PM and HF emitting units currently require the absence of regulation of HAP emissions, and total PM2.5 emissions percent water (or water and sediment) emissions from EGUs. The 2000 Finding based on the test results provided specifications between 0.5 percent and was based upon studies whose through part III of the 2010 ICR. We 1.0 percent. conclusions regarding the impacts from compared the measured emissions of Response: The EPA is providing the EGU emissions did not depend upon metals and PM with the uncontrolled alternative compliance assurance any relevant distinction between major emissions estimates and found that approaches in the final rule for liquid source and area source EGUs. The control of PM was indicative of the oil-fired EGUs of demonstrating commenters note that segregating control of metals emissions. In addition, compliance through either specific HCl ‘‘major source’’ and ‘‘area source’’ EGUs

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would have the perverse effect of regulatory burden of a CAA section 112 shows that many rather large EGUs (e.g., eliminating some of the best performing EGU rule on many small entities hundreds of MW) are also area sources, sources from the MACT pool of sources (arguing that many EGUs owned by and the commenters have not provided that constitute the ‘‘best performing’’ 12 small public power entities are area any justification for establishing GACT percent. Many of the best performing sources) and that as many as 12 percent standards for large synthetic area sources have employed control of the EGU population could qualify as sources. technology that brings their emissions area sources. A number of commenters Commenters did not provide an below the major source threshold, pointed out that the small entity evaluation of the health and despite the fact that they are larger representatives (SER) on the SBREFA environmental impacts of the area units. As a result, the commenters panel suggested that the EPA establish sources and simply presume that the believe that if the EPA created standards separate emission standards for EGUs risks from such sources are lower, even for ‘‘major source’’ EGUs based only located at area sources of HAP and that though many of the same commenters upon those units, the MACT standards the standards be based on GACT as noted that these smaller EGUs are often for ‘‘major source’’ EGUs would be less allowed under CAA section 112(d)(5). located in densely populated areas stringent for each of the pollutants than Specifically, the SERs recommended where populations are more likely to proposed in this Rule. At the same time, that the EPA establish management have adverse health effects from the the less polluting sources, the ‘‘area practice standards for area source EGUs. HAP emissions. Furthermore, other source’’ EGUs, could face limits more Response: The EPA is not establishing commenters, including some industry stringent than those proposed in the an area vs. major source distinction in commenters, noted that the vast Rule. Commenters also note that after the final rule. majority of these potential area sources reviewing the substantial record in this The CAA section 112(a)(8) definition meet the criteria due to the installation rulemaking, they believe that the EPA of EGU does not distinguish between of emission controls installed to meet has correctly determined that major and major and area sources, and we other requirements. According to these area source EGUs greater than 25 MW maintain that EGUs are a single source commenters, these synthetic area have similar HAP emissions and use the category that contains both major and sources would likely be able to meet the same control technologies and area sources. The EPA proposed to limits of this rulemaking and imposition techniques to reduce HAP emissions. regulate five subcategories of EGUs of this rule would not appear to result Thus, the commenters asserted that the without distinguishing between major in the installation of additional controls record demonstrates that there is no and area sources for purposes of in a number of cases. We do not know technical basis for distinguishing establishing the standards for the if this assertion is correct but we between major and area source EGUs for different subcategories. Our approach is determined approximately 69 coal-fired wholly consistent with the statutory purposes of establishing HAP emission EGUs will be able to meet the existing definition of EGU and reasonable. control standards under CAA section source MACT standards with their Nevertheless, the Agency did examine 112(d). current control configuration (out of 252 whether to set separate standards for EGUs that reported data for Hg, PM, and Many commenters in support of an area source EGUs, because we do not HCl in the 2010 ICR). area source designation for EGUs stated believe that the statute prohibits the Commenters also note that the Agency that the EPA has promulgated area Agency from exercising its discretion to has exercised its discretion in other source limits for many source categories establish GACT standards for area NESHAP rulemakings to establish area of HAP emissions, including most sources pursuant to CAA section source limits. Although true, the fact recently industrial boilers and note that 112(d)(5) if we determine such that the EPA has established area source GACT controls have been used standards are appropriate. The EPA is limits in some source categories is successfully in many other EPA MACT not required, however, to establish irrelevant to similar decisions for rules, including rules for iron & steel GACT standards for area sources, and different source categories. Commenters foundries, electric arc steelmaking, we believe it may even be unreasonable have not shown that the circumstances coatings operations, clay ceramics to do so under the circumstances we applicable to those other source manufacturing, glass manufacturing, identified in the proposed rule as categories are similar to the and secondary nonferrous metals supported by the record of this final circumstances identified for major and manufacturing, in order to reduce costs rule. area source EGUs (e.g., similar controls, and regulatory burdens. The At proposal, we determined that it similar emission characteristics, large commenters state that Congress has was not appropriate to establish number of synthetic minor area given the EPA the ability to separate standards for major and area sources). Further, those other source subcategorize area sources because of source EGUs, and even if we had categories are not statutorily defined in their low HAP emissions and low exercised our discretion to set separate a manner that includes both area and potential impact on human health and standards, we would have likely major sources. EGUs are the only source that, contrary to the plain language of declined to exercise our discretion to set category defined in CAA section 112 CAA section 112 and its legislative GACT standards for area source EGUs and, in establishing the definition of an history, the EPA made no attempt in the given our appropriate and necessary ‘‘electric utility steam generating unit’’ proposed rule to distinguish between finding and the fact that a potentially under CAA section 112(a)(8), Congress major sources and area sources for large number of area source EGUs are in included in the EGU source category purposes of listing or setting standards. fact large well controlled units. both area and major sources. Thus, it is The commenters indicated that where Some commenters note that there reasonable to regulate the EGU category Congress was concerned about the could be as many as 12 percent of the in the manner Congress defined the health impacts of specific pollutants total population that could be classified category. Commenters have provided no from specific sources, it knew how to as area sources. We are not sure of the legal support for the contention that the specify that MACT limits be commenters’ point in regard to this EPA must regulate area and major promulgated (e.g., CAA section statement. As to commenters’ sources in the same category in separate 112(c)(6)). The commenters state that statements that many of the area sources rulemakings, and the EPA has in fact area source rules would lessen the are municipal utilities, our information regulated both major and area sources in

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the same rulemaking even absent a would be no difference between MACT We fully evaluated the nature of statutory definition that includes both and GACT. Instead, it stated that it EGUs, and we do not see a basis on major and area sources. (See National would be difficult to make a distinction which to distinguish these sources for Emission Standards for Hazardous Air given the similarities between the EGUs purposes of setting standards. Thus, we Pollutants From the Portland Cement and major and area source facilities. maintain that we reasonably exercised Manufacturing Industry and Standards Specifically, as noted by other the discretion afforded the Agency of Performance for Portland Cement commenters, and observable by a review under the statute and declined to set Plants; 75 FR 54970; September 9, of the MACT Floor Analysis separate standards for area source EGUs. 2010.) spreadsheets, potential area sources E. Health-Based Emission Limits The EPA considered the totality of the range in size from units near the CAA circumstances when determining section 112(a)(8) defined lower size Comment: Many commenters noted whether to set separate area and major limit to units of hundreds of megawatts. that in the proposed rule the EPA source standards for EGUs and also Further, these larger area source units considered whether it was appropriate considered whether it would be are, for the most part, controlled with to exercise its discretionary authority to reasonable to establish GACT standards the full suite of emission control establish health-based emission limits for areas sources. We reasonably technologies available (e.g., fabric (HBEL) under CAA section 112(d)(4) for considered whether emissions filters, scrubbers). HCl and other acid gases and proposed characteristics of major and area sources In addition, the data that were not to adopt such limits, citing, among other things, information gaps regarding are different when determining whether available in the docket for the proposed facility-specific emissions of acid gases, to establish GACT standards, rule show that there is little difference co-located sources of acid gases and notwithstanding commenters’ assertion between major and area source EGUs their cumulative impacts, potential that such consideration is not correct. individually, and that generally the environmental impacts of acid gases, That we also consider emission driver for whether a utility facility is a and the significant co-benefits estimated characteristics in subcategorization major or area source depends on the from the adoption of the conventional decisions is of no consequence for area number of EGUs located at a facility MACT standard. Comments were source decisions. Given that the (almost exclusively one or two EGUs received both supporting this position statutory definition of EGUs contains located at area sources), not on any both major and area sources, it was and refuting it. Several commenters inherent difference between the EGUs suggested legal, regulatory and scientific reasonable to evaluate whether there themselves. See ‘‘Evaluation of Area were sufficient differences between area reasons for why HBEL for HCl might be Source EGUs’’ TSD, Docket EPA–HQ– and major sources when deciding appropriate for this MACT standard. OAR–2009–0234. In fact there are a whether to exercise our discretion to set With respect to legal concerns, some number of EGUs that are quite large that separate area and major source commenters indicated that CAA section are area sources and others that are standards. 112(d)(4) establishes a mechanism for In addition, we find commenter’s small that are major sources. Id. This is the EPA to exclude facilities from point concerning CAA section 112(c)(6) the case because the acid gas HAP certain pollution control regulations and odd because EGUs emit several of the emissions are what drive EGUs to have circumstances when these facilities can CAA section 112(c)(6) HAP (e.g., lead, HAP emissions exceeding the major demonstrate that emissions do not pose Hg). Although EGUs were exempted source threshold. With a few a health risk. Commenters cited a Senate from that provision, the fact that they exceptions, the EGUs located at area Report that influenced development of emit some of the HAP called out for sources have FGD or other acid gas CAA section 112(d)(4), where Congress MACT control supports our decision to controls that reduce the acid gas HAP to recognized that, ‘‘For some pollutants a not establish GACT standards for any area source levels. Id. Thus, the majority MACT emissions limitation may be far EGUs. CAA section 112(d)(5) leaves it to of sources that currently qualify as area more stringent than is necessary to the Agency’s discretion to determine sources were, in fact, major sources protect public health and the whether GACT standards should be prior to installing controls. The environment.’’ (Footnote: S. Rep. No. established for area sources, and the exceptions are those units that would 101–128 (1990) at 171.) Commenters statute does not require GACT standards likely be able to achieve the MACT level also cited regulatory precedent for or even indicate that such standards are of control for acid gas with minimal use addressing HCl as a threshold pollutant, to be the default regulatory approach for of DSI at a reasonable cost. Id. including the Hazardous Waste area sources. See 76 FR 25021. Instead, In addition, the data show that a Combustors and the Chemical Recovery the statute provides the Agency with number of area sources for which we Combustion Sources at Kraft, Soda, discretion and we have exercised it have data are high emitters of Hg and Sulfite, and Stand-Alone Semichemical reasonably in this case. non-Hg metal HAP. Id. Pursuant to our Pulp Mills NESHAP. Commenters Commenters indicate that many EGUs appropriate and necessary finding, these requested that the EPA incorporate the owned by small entities are potential HAP pose a significant threat to human flexibility afforded by CAA section area sources. However, commenters fail health. Thus, even were we to 112(d)(4) and allow sources reasonable to note that there are also EGUs owned distinguish between major and area means for demonstrating that their by small entities that are not potential sources, which we do not believe is respective emissions do not warrant area sources, and, thus, would not appropriate given the similarities further control. The commenters also accrue any ‘‘lessened regulatory between such sources, we would still cited the 2004 vacated Boiler MACT as burden’’ benefit from a decision by the decline to set GACT standards, and as precedent for HBEL for HCl. The EPA to establish area source standards. such we maintain that MACT standards commenters contended that the EPA Some commenters state that the EPA’s are appropriate. Moreover, for acid gas failed to explain why the health-based mere assertion that there would be no HAP, as discussed above, the data emissions limitations it established in difference between GACT and MACT to indicate that the level of control would the 2004 Boiler MACT and the justify an area source finding does not likely be the same even if we did justification provided for those provide sufficient documentation for the establish GACT standards under CAA limitations could not be used in this decision. But EPA did not say there section 112(d)(5). case. The commenters also cited a 2006

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court briefing where the EPA vigorously commenters suggested that other EPA to consider relevant factors when defended the HBEL included in the components of the CAA, such as the deciding whether to exercise its 2004 Boiler rule when it was challenged National Ambient Air Quality Standards discretion under CAA section 112(d)(4), in the D.C. Circuit (Final Brief For (NAAQS), are more appropriate avenues and, notwithstanding commenters’ Respondent U.S. Environmental for mitigating emissions of criteria assertions to the contrary, the Protection Agency, D.C. Cir. Case No. pollutants. considerations we include in our 04–1385 (Dec. 4, 2006) at 59–65, 69). Several other commenters suggested it analysis are reasonable. The EPA has Other commenters stated that on is impossible to assess an established considered the public comments August 6, 2010, the EPA adopted a health threshold for HCl such that a received and is not adopting an NESHAP for Portland Cement plants CAA section 112(d)(4) standard could emissions standard under CAA section that specifically rejected adoption of be set without evaluating the collateral 112(d)(4) for the reasons set forth in the risk-based exemptions or HBEL for HCl benefits of a MACT standard. And, as proposed rule and explained below. We and manganese (Mn). These described in the recently finalized note that this action is consistent with commenters argue there are no cement kiln MACT rule, setting EPA’s recent decisions not to develop differences sufficient to warrant a technology-based standards for HCl will standards under CAA section 112(d)(4) reversal of that decision in the EGU result in significant reductions in the for the Industrial, Commercial and MACT standard. The commenters raised emissions of other pollutants, including Institutional Boilers and Process Heaters concerns that health risk information SO2, Hg, and PM. The commenter added and the Portland Cement source cited by the EPA for HCl, HF, and that these reductions will provide categories. hydrogen cyanide (HCN) does not enormous health and environmental As explained in the preamble to the establish ‘‘an ample margin of safety’’ benefits, which would not be proposed rule, the EPA continues to and, therefore, no health threshold experienced if CAA section 112(d)(4) believe that the potential cumulative should be established. The commenters standards had been finalized. These public health and environmental effects believe risk-based exemptions at levels commenters contended that HCl and of all acid gas HAP emissions, not just less stringent than the MACT floor are other dangerous acid gases produced by HCl emissions, from EGUs and other prone to lawsuits that could potentially EGUs pose substantial risks to industrial acid gas sources located near EGUs further delay implementation of the workers, as well as surrounding supports the Agency’s decision not to EGU MACT. communities, and must be limited by exercise its discretion under CAA Some commenters disagreed with the strict conventional MACT standards. using a hazard quotient (HQ) approach Several commenters indicated that the section 112(d)(4). Additional data for all to establish a risk-based standard current economic climate requires the acid gas emissions were not provided because the HQ would not account for EPA to balance economic and during the comment period, and the potential toxicological interactions. The environmental interests and indicated data already in hand regarding these commenter noted that an HQ approach that HBEL would help target emissions are not sufficient to support incorrectly assumes the different acid investments into solving true health the development of emissions standards gases affect health through the same threats where limits are no more or less for EGUs under CAA section 112(d) that health endpoint, rather than assuming stringent than needed to protect public take into account the health threshold that the gases interact in an additive health. Many commenters provided for acid gas HAP, particularly given that fashion. This commenter suggested that estimates of compliance cost savings if the Act requires the EPA’s consideration a hazard index approach, as described an HBEL is included in this final rule. of health thresholds under CAA section in the EPA’s ‘‘Guideline for the Health Some commenters stressed the 112(d)(4) to protect public health with Risk Assessment of Chemical Mixtures,’’ importance of an HBEL for small an ample margin of safety. We note here would be more appropriate. entities affected by the regulations. that EPA agrees with the commenter Some commenters dispute that Several other commenters suggested who pointed out that a better way to emissions from other EGUs or source that the EPA should estimate the costs evaluate the potential health impact categories should be considered when and environmental effects of the HBEL interactions of all acid gases would be developing an HBEL and they argued option compared to a conventional to use the approach in EPA’s ‘‘Guideline that Congress expected the EPA to MACT standard in order to make an for the Health Risk Assessment of consider the effect of co-located informed decision on the adoption of Chemical Mixtures’’ rather than a facilities during the CAA section 112(f) HBEL. simple evaluation of individual HQ residual risk program instead of under Response: After considering the values for each acid gas, but we further CAA section 112(d). Commenters added comments received, the EPA has note that use of such an approach that there is no prior EPA precedent for decided not to adopt an emissions requires a substantially greater considering co-located facilities from a standard based on its authority under knowledge of acid gas emissions than is different source category during the CAA section 112(d)(4) for all the reasons currently available. We further note same CAA section 112 rulemaking. set forth in the proposed rule. that, even if cost were a relevant factor Several commenters disputed the The EPA notes that the Agency’s in setting standards under CAA section EPA’s consideration of non-HAP authority under CAA section 112(d)(4) 112(d)(4), since the data are not collateral emissions reductions in is discretionary. That provision states available that would allow us to develop setting MACT standards. They that the EPA ‘‘may’’ consider an acid gas HBEL appropriate to protect contended that the EPA’s sole support establishing health thresholds when public health with an ample margin of for its ‘‘collateral benefits’’ theory is setting emissions standards under CAA safety, we cannot determine whether legislative history—the Senate Report section 112(d). By the use of the term such standards would have any cost that accompanied Senate Bill 1630 in ‘‘may,’’ Congress clearly intended to savings associated with them or not. In 1989 and noted that the D.C. Circuit allow the EPA to decide not to consider addition, the concerns expressed by the rejected this use of this theory since the a health threshold even for pollutants EPA in the proposal regarding the Senate Report referred to an earlier which have an established threshold. As potential environmental impacts and version of the statute that was explained in the preamble to the the cumulative impacts of acid gases on ultimately not enacted. Instead proposed rule, it is appropriate for the public health were not assuaged by the

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comments received because no no valid reason that, in situations where year (4 years total) to 6 additional years significant data regarding these impacts the EPA has discretion in what type of (9 years total). Multiple commenters were received. standard to adopt, the EPA must ignore requested that a utility be required to The EPA also received comments controls which further the health and demonstrate good faith progress toward recommending not only that the EPA environmental outcomes at which CAA compliance to get any extension. Some establish emissions standards for acid section 112(d) is fundamentally aimed commenters suggested that the EPA gases pursuant to CAA section because such controls not only reduce require utilities to submit a notice 112(d)(4), but that it do so by excluding HAP emissions but emissions of other concerning which EGUs will be specific facilities from complying with air pollutants as well. Thus, the issue retrofitted or retired within 1 year of the emissions limits if the facility being addressed is not whether to effective date; that the compliance date demonstrates that its emissions do not regulate non-HAP under CAA section align with the Power Year used by pose a health risk. The EPA does not 112(d) or whether to consider other air RTOs; and that the EPA clarify that believe that a plain reading of the quality benefits in setting CAA section retirement and any clean replacement statute supports the establishment of 112(d)(2) standards—neither of which power that complies with the NESHAP such an approach. Although CAA the EPA is doing—but rather whether rule, including off-site combined heat section 112(d)(4) authorizes the EPA to EPA may exercise its discretion to and power and waste heat recovery, can consider the level of the health regulate certain HAP based on the be deemed ‘‘controls’’ under the CAA. threshold for pollutants which have an MACT approach and consider collateral Commenters noted the specific established threshold, that threshold health and environmental benefits when situations related to small entities and may be considered ‘‘when establishing choosing whether to exercise that their inability to compete with the emissions standards under [CAA section discretion. The EPA believes there is no larger, investor-owned utilities for 112(d)].’’ Therefore, the EPA must still legal principle that precludes it from financing and engineering and technical establish emissions standards under doing so and commenters have not labor as well as the different process CAA section 112(d) even if it chooses to provided one. they need to follow for capital exercise its discretion to consider an improvements. Multiple commenters established health threshold. A source- F. Compliance Date and Reliability asked that the EPA consider other by-source standard is not mandated as Issues simultaneous rulemakings (e.g., Cooling some commenters seem to imply, and Comment: Multiple commenters Water Intake Structures; Coal we are unsure how we could reasonably asked that the compliance date be Combustion Residuals; CSAPR, etc.) and implement such an approach even if we clearly stated as soon as possible, as extend the compliance period. Many determined such an approach was well as that guidance be provided for commenters noted these other legally available. For these reasons utilities unable to comply with the requirements and suggested that alone, we concluded it was not stated timelines, to allow time for installation of the necessary controls appropriate to exercise our discretion to utilities to prepare for compliance. could not be completed within the establish section 112(d)(4) standards for Commenters also asked that any compliance period allowed under CAA acid gas HAP emissions. decisions or policies on extensions be section 112, even if a fourth year were In addition, as explained in the published in a rulemaking. In addition, to be granted by the permitting preamble to the proposed rule, the EPA commenters requested that the EPA authority, citing examples of the times also considered the co-benefits of setting establish, streamline, and simplify the necessary for installation of various a conventional MACT standard for HCl. process of applying for the 1-year pieces of control equipment or The EPA considered the comments extension under CAA section 112(i)(3). replacement power. received on this issue and continues to Multiple commenters offered Some commenters pointed to existing believe that the estimated co-benefits suggestions on methods for allowing state programs (e.g., Colorado, Oregon, are significant and provide an more time for compliance, including Washington) and indicated that if states additional basis for the Administrator to EPA’s authority under CAA section can demonstrate that overall emissions conclude that it is not appropriate to 112(n)(1)(A); state authority under CAA reductions would be equivalent or exercise her discretion under CAA section 112(i)(3); Presidential authority greater than those that would be section 112(d)(4). The EPA disagrees under CAA section 112(i)(4); categorical achieved by the proposed rule, the EPA with the commenters who stated that it extensions for publicly-owned or should delegate the CAA section 112 is not appropriate to consider non-HAP governmental facilities according to EO program to these states, even if the state benefits in deciding whether to invoke 13132, 13563, and UMRA of 1995; state- emissions reductions would not CAA section 112(d)(4). Although MACT designed programs under the delegation necessarily occur on the same schedule standards may directly regulate only provisions of CAA section 112; various (many state programs call for retirement HAP and not criteria pollutants, Consent Decrees; Administrative Orders of EGUs in years beyond the CAA Congress did recognize, in the of Consent (AOCs); temporary waiver section 112 compliance date). The legislative history to CAA section mechanisms; and adoption of MACT commenters did not want the 112(d)(4), that MACT standards would compliance schedules through minor promulgation of the final rule to have the collateral benefit of controlling permit modifications of a source’s Title undermine the significant amount of criteria pollutants as well and viewed V federal operating permits. Absent work that may have been invested in this as an important benefit of the air such considerations for additional creating state-specific programs to curb toxics program. See S. Rep. No. 101– compliance time, many commenters emissions within a reasonable 228, 101st Cong. 1st sess. at 172. The suggested that the reliability of the timeframe. The commenters seek to EPA consequently does not accept the nation’s electric grid would be make use of temporal flexibility, argument that it cannot consider jeopardized as utility companies were authorized under CAA section 112(i)(3), reductions of criteria pollutants in forced to retire EGUs because they could in obtaining delegation of the final rule determining whether to take or not take not install the needed controls in the to preserve the hard-negotiated certain discretionary actions, such as requisite time. comprehensive state-specific programs whether to adopt an HBEL under CAA Compliance times requested by designed to yield greater emission section 112(d)(4). There appears to be commenters ranged from 1 additional reductions than the MATS alone.

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Other commenters requested that no A number of commenters expressed existing sources can be met by most additional time be granted for concern that the time frame for sources without adversely impacting compliance. These commenters compliance with a regulation under electric reliability. In particular, EPA reference a number of reports (e.g., by CAA section 112(d) was too short for believes that the flexibility of permitting the URS Corporation, by M.J. Bradley & this industry and would result in authorities to allow a fourth year for Associates and the Analysis Group, and compromising the reliability of compliance should be available in a by the Bipartisan Policy Center) to electricity supply. Commenters asserted broad range of situations (as discussed indicate that not only is technology that reliability would be compromised below), and that this flexibility readily available, but that the in several ways: (1) EGUs might have to addresses many of the concerns that technology can typically be installed in temporarily close if the owner or have been raised. Furthermore as less than 2 years and that the electric operator is unable to install controls on indicated below, in the event that an industry is well-positioned to comply the unit within the 3-year time frame or isolated, localized concern were to with the EPA’s proposed air regulations 3 years plus one; (2) the timing of emerge that could not be addressed without threatening electric system outages to install controls will cause solely through the 1-year extension reliability. Commenters assert that, if short term closures that could threaten under CAA section 112(i)(3), the CAA electric system reliability were to be grid stability; (3) owner/operators may provides flexibilities to bring sources threatened in local areas as a result of shut down EGUs rather than invest in into compliance while maintaining the rule, the EPA has the statutory retrofits to keep them running and that reliability. these closures may cause a loss of authority to grant, on a case-by-case The EPA considered the impact that critical generation; and (4) the basis, extensions of time to complete the potential retirements in response to this construction of replacement generation installation of pollution control systems. rule will have on resource adequacy in or implementation of other measures to One commenter stated that no order to gauge the rule’s impact on address reliability concerns due to plant additional controls would need to be reliability. In considering these impacts, retirements could take longer than 3 installed in many cases and any coal the EPA considered both the analysis it years, and that units slated for closure unit should be able to comply with all has conducted as well as analyses may be necessary beyond the 3-year of the standards. Another commenter compliance period but will be unable to conducted by a number of other groups. noted that utilities that failed to plan run because they have not installed the The EPA’s analysis shows that the ahead ‘‘should not be permitted to use necessary controls. expected retirements of coal-fueled their own inaction to justify more time.’’ Response: Clean Air Act section 112 units as a result of this final rule (4.7 Commenters noted that several major specifies the dates by which affected GW) are fewer than was estimated at utility companies have anticipated the sources must comply with this rule. proposal and much fewer than some 321 EPA’s rules and are already taking New or reconstructed units must be in have predicted. The net capacity action to ensure a reliable supply of compliance immediately upon startup reductions projected by the EPA make electricity in their service territory and or the effective date of this rule, up less than one-half of one percent of beyond. Other commenters agree that whichever is later. Existing sources may the total generating capacity in the U.S. there is significant excess generation be provided up to 3 years after the and about one and one-half percent of capacity in the country and reliability effective date to comply with the final U.S. coal capacity. Because concerns will not be threatened by the rule. rule; if an existing source is unable to have been raised that the use of DSI may According to one commenter, comply within 3 years, a permitting not be as prevalent as the Agency has companies are already preparing for a authority has the ability to grant such a predicted and because this could lead to 2015 compliance date, factoring in the source up to a 1-year extension, on a more coal retirements, the Agency also capital expenditures required to comply case-by-case basis, if such additional performed a sensitivity analysis in and delays would undermine decisions time is necessary for the installation of which fewer DSI systems and more that have already been made. controls. scrubber systems were installed. In that Commenters cite, for example, recent As is explained earlier in this sensitivity, we see approximately 1 electricity forward capacity market preamble, the 3-year compliance more GW of retirements. This small auctions in the PJM market for the window is based on the date that is 60 change would have only a very small period of 2014 and 2015 that indicate days after publication of this rule in the potential impact on resource adequacy. that the capacity markets cleared with Federal Register. Because publication When considering the impact that one electricity reserve margins of 20 percent; doesn’t occur until several weeks after specific action has on power plant this is in excess of the default reliability the rule is signed by the Administrator, retirements, it is important to targets used by the North American the earliest required date for compliance understand that the economics that Electric Reliability Corporation (NERC) would be sometime in March 2015. drive retirements are based on multiple for the year 2015. One commenter Because the last stage of control factors including: expected demand for quoted NERC, stating that NERC does installations usually needs to occur electricity, the cost of alternative not see impacts from proposed climate when the unit is off-line and because generation, and the cost of continuing to legislation or anticipated EPA regulation scheduled outages are usually generate using an existing unit. The as a reliability concern. Another scheduled for the spring or fall months EPA’s analysis shows that the lower cost commenter noted that the Building and when peak electric demand is lower, of alternative fuels, particularly natural Construction Division of the AFL–CIO this additional time is significant as it gas, as well as reductions in demand, has stated that there is no evidence to provides companies an additional will have a greater impact on the suggest that the availability of skilled outage period, the spring of 2015, to manpower will constrain pollution install controls. 321 The EPA’s analysis also identifies a small control technology installation. In fact, The EPA has considered the concerns amount of capacity loss (less than 0.7 GW) due to according to the commenter, given the raised by commenters and has derating of certain units, as well as partially concluded that given the flexibilities offsetting reductions in non-coal retirements in high levels of unemployment in the comparison with the base case. The net estimated construction sector, these jobs are much further detailed in this section, the reduction in capacity, in comparison with the base needed. requirements of the final rule for case, is estimated at less than 5 GW.

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number of projected retirements than concluding that ‘‘scenarios in which towers. In one study, the reliability will the impact of this final rule. electric system reliability is broadly effects reported are based on inaccurate The EPA’s assessment looked at the affected are unlikely to occur.’’ 323 assumptions that all existing EGUs with capacity reserve margins in each of 32 In August 2011, PJM a capacity utilization factor of less than subregions in the continental U.S. Interconnection—the Regional 35 percent would close, and that all in- Demand forecasts used were based on Transmission Operator (RTO) scope electric generators would be EIA projected demand growth. The responsible for planning and reliable required to install cooling towers within analysis shows that with the addition of operation of the bulk power system 5 years, whereas the not-selected very little new capacity, average reserve serving all or portions of 13 states in the options with closed cycle cooling in margins are significantly higher than Mid-Atlantic and Midwestern regions— EPA’s proposal envisioned that permit required. The NERC assumes a default issued a report analyzing the impacts of authorities could exercise discretion to reserve margin of 15 percent while the the CSAPR and the proposed MATS allow facilities 10 to 15 years’ time to average capacity margin seen after rule.324 Although PJM’s analysis comply. In most cases, these analyses implementation of the policy is nearly assumes substantially more retirements were performed before the CWA section 25 percent. Although such an analysis than EPA projects, it nevertheless 316(b) rule or the MATS rule were even does not address the potential for more concludes that resource adequacy is not proposed; even analyses subsequent to localized reliability concerns associated threatened in the PJM region. This is the CWA section 316(b) proposal with transmission constraints or the particularly significant, given that the continue to inaccurately portray EPA’s provision of location-specific ancillary PJM region is one of the largest and proposed approach. services (such as voltage support and most heavily dependent on coal-fueled Second, in reporting the number of black start service), the number of generation in the country. The PJM retirements, many analyses fail to retirements projected suggests that the analysis notes, as EPA has differentiate between plant retirements magnitude of any local reliability acknowledged, that even where there is attributable to the EPA rules and concerns should be manageable with adequate generation capacity on a retirements of older, smaller, and less existing tools and processes. regional basis, localized reliability efficient plants that are already Several outside analyses have reached issues may emerge in connection with scheduled for retirement because conclusions consistent with EPA’s retirements that may need to be owners have made business decisions, analysis. The DOE, in December 2011, addressed. based in significant part on market published a report that looked at The EPA has reviewed industry and conditions, not to continue operating resource adequacy in the bulk power NERC studies suggesting, contrary to the them. system when faced with a stress test EPA’s and these other groups’ analyses, Third, most of these analyses fail to which was a regulatory scenario far that EPA rules affecting the power account for the broad range of responses more stringent than EPA’s sector (including this final rule, the available to address electric reliability regulations.322 For this stress test, in CSAPR, EPA’s proposed rule addressing concerns associated with power plant addition to CSAPR and MATS power plant cooling water intake retirements, including upgrades to the requirements, each uncontrolled electric systems under section 316(b) of the transmission system, construction of generator is required to install both a Clean Water Act (CWA), and EPA’s new generation, and implementation of wet FGD system and a fabric filter to proposed rule addressing coal demand-side measures. These measures reduce air toxics emissions. If such combustion residuals under the are discussed at greater length below. installations are not economically Resource Conservation and Recovery As a preliminary matter, none of these justified, this scenario assumes that the Act) will result in substantial power situations, either alone or in plant must retire by 2015. In reality, as plant retirements. Some of these studies combination, will necessarily lead to an discussed previously, power plant predict that such levels of retirements electric reliability problem. There is owners will have multiple other will have adverse effects on electric excess generating capacity in the U.S. technology options to comply with the reliability in some regions of the today and in most cases an EGU that regulations—options that typically cost country. Although the specifics of these closes, either temporarily until it comes less than installations of FGDs and analyses differ, in general they share a into compliance or permanently, will fabric filters. The analysis finds that number of serious flaws in common that not cause a reliability problem. As target reserve margins can be met in all call their conclusions into question. explained above, our modeling of the regions, even under these stringent First, most of these studies make impact of this final rule at the regional assumptions. Moreover, in every region assumptions about the requirements of level projects retirements of less than but one (TRE), no additional new the EPA rules that are inconsistent with, one percent of nationwide generating capacity is needed. In TRE, the analysis and dramatically more expensive than, capacity and confirms that there will finds that less than 1 GW of new natural the EPA’s actual proposals or final rules. continue to be adequate capacity in all gas capacity would be needed by 2015 For example, a large proportion of the 32 subregions of the country as sources beyond the additions already projected retirements projected by several of these comply with the rule.325 This analysis to occur in the Reference Case. This studies is attributable to their inaccurate shows that significantly less capacity analysis also finds that the total amount assumption that EPA’s cooling water will close in response to the final rule of new capacity that would be added by intake rule under CWA section 316(b) than might have under the proposal. 2015 is less than the amount that is would require all or virtually all Moreover, the regional modeling of already under development. existing power plants to install cooling retirements demonstrates that plants In June 2011, the Bipartisan Policy that close in response to this rule are Center issued a report analyzing 323 Bipartisan Policy Center, June 2011, spread out across the country rather potential collective impacts of EPA’s ‘‘Environmental Regulation and Electric System than clustered in one area. Reliability.’’ Outside analyses have identified pending power sector rules and 324 PJM Interconnection, August 26, 2011, ‘‘ Coal Capacity at Risk for Retirement in PJM: Potential many of the same flaws in studies 322 U.S. Department of Energy, December 2011, Impacts of the Finalized EPA Cross State Air ‘‘Resource Adequacy Implications of Forthcoming Pollution Rule and Proposed National Emissions 325 See Technical Support Document on Resource EPA Air Quality Regulations.’’ Standards for Hazardous Air Pollutants.’’ Adequacy in this Docket.

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projecting large-scale retirements as a integrated resource planning, and in line by the third quarter of 2014.329 The result of EPA’s power sector rules. For some cases, forward auctions for future EPA notes, as well, that in the 3 years example, on August 8, 2011, the generating capacity) that ensure that from 2001 to 2003, industry brought Congressional Research Service companies adequately plan for, and over 160 GW of generation on line.330 (CRS) 326 issued a report concluded that markets are responsive to, future Demand side options include energy studies that assert that EPA rules will requirements such as this final rule. efficiency as well as demand response cause reliability problems, often make Second, companies that intend to programs. These types of resources can assumptions about the requirements of retire EGUs should formally notify their also be developed very quickly. In 2006, the rules that are inconsistent with, and RTO (or comparable planning authority PJM had less than 2,000 MWs of dramatically more expensive than, the in the case of non-RTO regions), state capacity in demand side resources. EPA’s actual proposals. The CRS further regulatory agencies, and regional Within 4 years this capacity nearly noted that EPA’s rules will primarily reliability entities as soon as possible of quadrupled to almost 8,000 MW of affect units that are more than 40-years their compliance plans, particularly capacity.331 In addition to helping old, that have not yet installed state-of- with regard to any planned unit address reliability concerns, reducing the-art pollution controls, and that are retirements. As we said before, in most demand through mechanisms such as inefficient. Many of these plants are places a closing plant will not be a energy efficiency and demand side being replaced by combined cycle cause for concern for reliability. The management practices has many other natural gas plants, driven more my same is true of any outages required for benefits. It can reduce the cost of lower gas prices than by EPA’s retrofitting of units with controls. To the compliance and has collateral air regulations. The June 2011 Bipartisan extent there is concern, however, early quality benefits by reducing emissions Policy Center report referenced above notification will provide an opportunity in periods where there are peak air likewise highlighted many of these same for transmission planners, market quality concerns. shortcomings in the studies in participants, and state authorities to With regard to transmission, recent question.327 develop solutions to avoid a reliability experience also shows that, in many Although we do not expect to see any problem. In RTOs with forward capacity cases, transmission upgrades to address regional reliability problems, we markets, owner/operators that do not reliability issues from plant closures can acknowledge that there could be bid generating capacity that they plan to be implemented in less than 3 years. For localized reliability issues in some instance, when Exelon notified PJM of shut down will provide an advance 332 areas—due to transmission constraints signal to market participants to take its intention to retire four units, it or location-specific ancillary services action to assure adequate future was determined that transmission provided by retiring generation—if capacity. In all regions, early and public upgrades necessary to allow retirement utilities and other entities with notification will allow market of two units could be made within 6 months of notification, transmission responsibility for maintaining electric participants, planning coordinators and upgrades for the third unit would reliability do not take actions to mitigate state authorities, as appropriate and in require slightly over 1 year and such issues in a timely fashion. There a timely fashion, to bring new transmission upgrades to allow the are many potential actions that could be generation on line, put demand side fourth unit to retire could be made in taken to address this problem and resources in place, and/or complete any approximately 18 months.333 multiple safeguards to assure a reliable transmission upgrades needed to The CAA allows CAA Title V electricity supply. circumvent a potential issue. Most RTOs permitting authorities the discretion to First, utilities can help to assure only require 45 to 120 days notification grant extensions to the compliance time reliability through proactive steps in of closure. In combined comments to of up to one year if needed for coordination with relevant planning and EPA, 5 RTOs suggested that such installation of controls. See CAA section regulatory authorities. As we said in the notification should be made no later 112(i)(3)(B)). If an existing source is proposal, early planning is key. The than 12 months after this regulation is unable, despite best efforts, to comply industry has adequate resources to final in order to allow a smooth within 3 years, a permitting authority install the necessary controls and transitioning to action to avoid a has the discretion to grant such a source develop the new capacity that may be reliability problem. The EPA strongly up to a 1-year extension, on a case-by- required within the compliance time encourages sources to provide notice to case basis, if such additional time is provided for in the final rule.328 the RTOs as early as possible and necessary for the installation of controls. Although there are a significant number believes that responsible owner/ Id. Permitting authorities should be of controls that need to be installed operators should and will do the early familiar with the operation of the 1-year across the industry, with proper planning for compliance and provide planning, we believe that the early notification of their compliance 329 Paul M Sotkiewicz, PJM Interconnection, compliance schedule established by the plans, especially where such plans Presentation at the Bipartisan Policy Commission CAA can be met. Many companies have include retiring one or more units. Workshop Series on Environmental Regulation and begun to do the detailed analysis and On the supply side, there are a range Electric System Reliability, Workshop 3: Local, engineering and are ahead of others in State, Regional and Federal Solutions, January 19, of options including the development of 2011, Washington, DC, http:// their compliance strategy. There are more centralized power resources www.bipartisanpolicy.org/sites/default/files/ already tools in place (such as (either base-load or peaking) and/or the Paul%20Sotkiewicz-%20Panel%202_0.pdf, slide 6. development of cogeneration or 330 Form EIA–860 Annual Electric Generator 326 James E. McCarthy and Claudia Copeland, distributed generation. Even with the Report, http://www.eia.gov/cneaf/electricity/page/ Congressional Research Service, August 8, 2011, eia860.html. ‘‘EPA’s Regulation of Coal-Fired Power: Is a ‘Train current large reserve margins, there are 331 BPC slides cited above—slide 5. Wreck’ Coming?’’. companies ready to implement supply- 332 http://www.exeloncorp.com/Newsroom/pages/ 327 Bipartisan Policy Center, June 2011, side projects quickly. For instance, in pr_20091202_Generation.aspx?k=eddystone. ‘‘Environmental Regulation and Electric System the PJM region, there are over 11,600 333 Cromby Units 1 and 2 and Eddystone Units 1 Reliability.’’ MW of capacity that have completed and 2—Deactivation Study, Updated September 7, 328 As stated above, EPA has provided the 2010—http://policyintegrity.org/documents/ maximum compliance time authorized under CAA feasibility and impact studies; the units 20100907-cromby-and-eddystone-retirement-study- section 112(i)(3)(A). representing this capacity could be on- posting-update.pdf.

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extension provision because EPA has The EPA took comment on whether generation, a determination that an extra established regulations to implement the construction of on-site replacement year is necessary for compliance should the provision and the provision applies power could be considered the be relatively straightforward. In order to to all NESHAP. See 40 CFR ‘‘installation of controls’’ such that a install controls, companies will have to 63.6(i)(4)(A). fourth year would be available while the go through a number of steps fairly early We believe that the permitting replacement unit is being completed for in the process including obtaining authorities have the discretion to use a unit that is retiring (e.g., a case when necessary building and environmental this extension authority to address a a coal-fueled unit is being shut down permits and hiring contractors to range of situations in which installation and the capacity is being replaced on- perform the construction of the schedules may take more than 3 years site by another cleaner unit such as a emission controls or replacement including: staggering installations for combined cycle or simple cycle gas power. This should provide sufficient reliability reasons or other site-specific turbine). After reviewing the comments, information for a permitting authority to challenges that may arise related to EPA believes that it is reasonable for determine that emission controls are source-specific construction, permitting, permit authorities to allow the fourth being installed or that replacement or labor, procurement or resource year extension to apply to the power is being constructed. Because challenges. Staggered installation allows installation of replacement power at the companies will need to develop this companies to schedule outages at site of the facility. The EPA believes that information early in the process and multiple units so that reliable power can building replacement power constitutes because a determination can easily be be provided during these outage the ‘‘installation of controls’’ at a facility made as to whether the schedule will periods. It can also be helpful for to meet the regulatory requirements. exceed 3 years, the EPA believes that particularly complex retrofits (e.g., Commenters were generally Title V permitting authorities should be when controls for one unit need to be supportive of the proposed approach able to quickly make determinations as located in an open area needed to described above, but a number of to when extensions are appropriate. construct controls on another unit). The commenters suggested several In the three cases related to retirement additional 1-year extension would additional situations that should be of a unit without construction of onsite provide an additional two shoulder considered as the ‘‘installation of replacement power, additional periods (i.e., seasons flanking annual controls’’ such that it would be information is needed. The Title V high-demand periods) to schedule appropriate for permitting authorities to permitting authority should request that grant a 1-year extension beyond the 3- the affected company or companies outages, thus enabling owners/operators year compliance time-frame. In provide information, including, for to gain the full benefit of staggering particular, commenters suggested that example, from the RTO or other outages in support of complex the 1-year extension should be available planning authority for the relevant installations. The EPA believes that for a unit if a company’s compliance region, the state electric regulatory although most units will be able to fully choice was to retire that unit but doing agency, NERC or its regional entities, comply within 3 years, the fourth year so within the 3-year time-frame caused and/or FERC or the DOE, demonstrating that permitting authorities are allowed reliability problems for any of the that retirement of a particular unit to grant for installation of controls is an following reasons: (1) Generation from within the 3-year compliance period important flexibility that will address the retiring unit is needed to maintain would result in a serious risk to electric situations where an extra year is reliability while other units install reliability. necessary. That fourth year should be emission controls; (2) new off-site The first two situations involving a broadly available to enable a facility generation was being built to replace the retiring unit—where one or more related owner to install controls within 4 years retiring unit, but the new generation existing units are upgrading pollution if the 3-year time frame is inadequate for was not scheduled to be operational controls or a new unit is being completing the installation. within the 3-year time-frame and any constructed off-site—are similar to the As we indicated at proposal, this gap between the time the existing unit situation we discussed in the proposed source category is unique due to the retires and the new unit comes on line rule wherein a retiring unit at a facility large, complex and interconnected would cause reliability problems; and runs an additional year while a nature of electrical generation, (3) transmission upgrades were needed replacement unit on the same site is transmission and distribution, and the in order to maintain electric reliability constructed. In each of these situations, critical role of the electric grid in the after the unit retired but could not be the retiring unit would be allowed to functioning of all aspects of the completed within 3 years. run so a unit compliant with the rule economy. The grid functions as an While the ultimate discretion to (either a retrofitted existing unit or a interconnected system that supplies provide a 1-year extension lies with the new unit) can come on line. We believe electricity to end users on a continuous permitting authority, EPA believes that that these situations may, in the basis. Safe, reliable operation of the grid all three of these cases may provide appropriate circumstances, constitute requires coordination among actions reasonable justification for granting the ones in which a 1-year extension for the taken at individual units, including 1-year extension if the permitting retiring unit is ‘‘necessary for the timing of outages for the installation of authority determines, for example, installation of controls.’’ In these two controls, derating, or deactivation. It based on information from the RTO or situations, however, we believe that it was for this reason that we specifically other planning authority or other would be appropriate for the Title V addressed in the proposed rule entities with relevant expertise, that permitting authority to consider reasonable interpretations of the phrase continued operation of a particular unit reliability concerns as a necessary factor ‘‘installation of controls’’ in CAA slated for retirement for some or all of before granting the additional year section 112(i)(3)(B). We determined that the additional year is necessary to avoid because continuing operation of the it was important to provide Title V a serious risk to electric reliability. retiring unit is only ‘‘necessary’’ to the permit authorities with information that In a case where pollution controls are extent it is required for reliability. In might be useful if they were asked to being installed, or onsite replacement each of these situations, the permitting authorize a fourth year for specific power is being constructed to allow for authority should determine that the EGUs. retirement of older, under-controlled retiring unit is necessary to maintain

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reliability until the new unit comes on some measure of flexibility is with those cases, but that they may not be line or the other existing unit is respect to the exercise of its fully addressed. The EPA is supportive retrofitted. Title V permitting authorities enforcement authorities. The Agency of such efforts and believes they can may determine that multiple retiring has used such authority in the past to have important multi-pollutant health units are available to maintain bring sources into compliance with the and environmental benefits. To the reliability, but unless all the units are requirements of the CAA while extent that the flexibilities discussed necessary to address the issue, it would maintaining electric reliability, although here do not fully address a particular likely be unreasonable to provide the these authorities are not as flexible as situation, we encourage states and additional year for all the identified suggested by some commenters. sources to contact the EPA as early as units. The EPA generally does not speak possible to discuss their individual The third hypothetical situation publicly to the intended scope of its circumstances. identified above is one in which enforcement efforts, particularly well in transmission upgrades are necessary to advance of the date when a violation G. Cost and Technology Basis Issues address a reliability issue resulting from may occur. In light of the importance of 1. Dry Sorbent Injection the retirement of a unit in order to ensuring electric reliability, however, Comment: Several commenters stated comply with this rule, where the the Office of Enforcement and that there is limited commercial upgrade cannot be completed by the 3- Compliance Assurance will separately operating experience in using DSI to year compliance date. In terms of the publish a document that articulates our control acid gas emissions from coal- functionality of the electric grid, this intended approach with respect to fired boilers. They suggest that the situation has some similarity to those sources that operate in noncompliance technology is not adequately proven for discussed above. Here, it is the with this final rule to address a specific use in this application. completion of the transmission and documented reliability concerns. Other commenters disagree with upgrades, rather than bringing another That document provides a pathway statements made that DSI is not proven. compliant (retrofitted or new) unit on for reliability critical units (as such One commenter stated that DSI is a line, that would allow the retiring unit units are described in the document) to mature technology. The commenter to come into compliance (by retiring) achieve compliance within an indicated that DSI is well suited for without threatening reliability. The additional year. The result is that units that burn fuels with lower or mid- general objective and result is similar: qualifying reliability critical units may level sulfur contents, and is among the Reductions of the existing unit’s HAP come into compliance within up to 5 viable options available for a number of emissions (through retirement) while years. This pathway is structured to sources to achieve the proposed HCl maintaining electric reliability. If such maintain reliability, to ensure CAA limits. Thus, the commenter believes situations develop and the reliability compliance and to increase certainty for that DSI represents a real technology problem has been properly sources in planning by allowing a unit control option for many units, and is demonstrated, permitting authorities owner/operator to determine whether it among the suite of technology options should consider whether an extension qualifies for a compliance schedule well that certain units will be able to employ under CAA section 112(i)(3)(B) may be in advance of the MATS compliance to meet the proposed HCl limit. provided. deadline. Response: As explained in this The EPA continues to believe, based The EPA believes that there will be response and elsewhere in this on the analysis discussed at the few, if any, situations in which it will preamble, the EPA agrees that DSI beginning of this section, that most, if be necessary to have recourse to the technology is proven and ready for not all, units will be able to comply processes discussed in the document commercial use in controlling acid gases with the requirements of this rule just described, and that there are likely from coal combustion. One of the largest within 3 years. The EPA also believes to be fewer, if any, cases in which it is coal-burning electric utilities in the U.S, that making it clear that permitting not possible to mitigate a reliability American Electric Power (AEP), authorities have the authority to grant a issue within the further year pioneered the practical use of DSI with 1-year compliance extension where contemplated under that document. trona, a sodium-based sorbent, for SO3 necessary, in the range of situations However, there is always the possibility mitigation. American Electric Power has described above, addresses many of the that some unit owner/operator will be implemented trona injection for that other concerns that commenters have unable to address its reliability issues purpose across its entire bituminous raised. The EPA believes that the within 5 years and there is always the coal-fired fleet where both SCR and wet number of cases in which a unit is possibility that a unit owner/operator FGD systems are in place.334 Examples reliability critical and in which it is not will be unable to timely comply with of coal-fired EGUs already using trona possible to either install controls on the the MATS for some other reason. DSI to control SO2 emissions include unit or mitigate the reliability issue Consistent with its longstanding NRG Energy’s Dunkirk Generating through construction of new generation, historical practice under the CAA, the Station Units 1–4 and CR Huntley Units transmission upgrades, or demand-side EPA will address individual non- 67 and 68 in New York.335 The Dunkirk measures, within 4 years, is likely to be compliance circumstances on a case-by- units range in size from 75 MW to 190 very small or nonexistent. This view is case basis, at the appropriate time, to MW. Much larger units may also be consistent with statements from determine the appropriate response and economic when using DSI for SO2 commenters explicitly mandated with resolution. control, as suggested by Dominion ensuring grid reliability. A number of commenters also raised Energy’s studies of adding DSI on two The EPA’s authority to provide relief concerns about inconsistencies between

from the requirements of this final rule the compliance timelines under this 334 SO3 Control: AEP Pioneers and Refines Trona beyond the fourth year is limited by the final rule and existing state agreements Injection Process for SO3 Mitigation, Coal Power, statute. If reliability issues do develop, with specific owners/operators to install March 2007, http://www.coalpowermag.com/ however, the CAA provides pollution control equipment and/or plant_design/SO3-Control-AEP-Pioneers-and- Refines-Trona-Injection-Process-for-SO3- mechanisms for sources to come into retire EGUs. The EPA believes the Mitigation_29.html. compliance while maintaining electric flexibilities provided in this discussion 335 NRG Energy letter to RGGI, Inc, November 22, reliability. One area where the EPA has allow for some discretion to address 2010, http://www.rggi.org/docs/NRG_Nov_2010.pdf.

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625 MW units at the Kincaid plant in containing sodium and other at the University of North Dakota.339 Illinois.336 One of the largest suppliers compounds that are challenging to The EERC’s testing of trona DSI on a of air emission control systems in the handle, thus requiring special landfill central Appalachian bituminous coal world, vouches that DSI is commercially designs and a high cost for landfill (1.3 lb SO2/MMBtu) substantiates the proven for acid gas control:337 338 disposal of DSI waste. strong HCl reaction selectivity of Comment: Numerous comments were Response: The EPA believes that its sodium-based sorbents, including trona, received on EPA’s IPM modeling of DSI representation of DSI in MATS and calcium-based hydrated lime. The in the MATS analysis. A few compliance modeling is reasonable, is EERC’s pilot testing shows that fine- commenters stated that DSI will not properly limited to applications that are milled trona, when well mixed into 325 work on bituminous coals. Some technically feasible, and reflects a °F flue gas upstream of a FF, provides commenters stated that DSI is only conservative approach to modeling 90 percent HCl removal at a SO2 suitable for use on low sulfur, low future use of this technology. removal rate of less than 20 percent (as chlorine western coals. Others stated The EPA disagrees that its IPM compared to EPA’s modeling that DSI is only likely to be used on modeling of DSI is overly optimistic and assumption of aligning 90 percent HCl relatively small units, and that larger therefore underestimates the costs of removal with sorbent injection designed units would use scrubbers for acid gas MATS compliance. In its IPM modeling, to achieve 70 percent SO2 removal). The control. Several commenters expressed EPA restricts the availability of the DSI data show that 95 percent or higher HCl the opinion that because there is little option to only those units that use or removal is readily obtained at somewhat commercial operating experience in switch to relatively low sulfur coal: Less higher SO2 removal rates. Similarly using DSI to control SO2 emissions from than 2 lb SO2/MMBtu (see IPM strong HCl selectivity results were coal-fired boilers, EPA’s IPM modeling documentation in the docket). The obtained using trona and an ESP at assumptions on the efficacy and cost of EPA’s IPM projections for MATS 650 °F. Test data from United the DSI control option are unjustifiably compliance, therefore, already include Conveyor 340 on full-scale units also optimistic. Some commenters believe the costs of any additional FGD show these high HCl selectivity trends. that DSI will not be as economic or as scrubbers that are economically justified Overall, these test data from multiple and projected for use on units using widely applicable for either SO2 or HCl major vendors suggest that even if a SO2 control as projected by EPA’s IPM higher sulfur coals. The EPA models removal rate of 30 percent were required modeling. Commenters observe that wet DSI assuming fine-milled trona as the in order to obtain 90 percent HCl or dry scrubbers for FGD, longer- injected sorbent. As mentioned by removal in the imperfectly mixed flow several commenters, sodium standing control technologies for SO2 of a full-scale unit, it still appears that and HCl, are more complex systems bicarbonate (SBC), which is processed EPA’s assumed trona injection rates may with a much higher capital cost than from trona, is also suitable for use with be as much as twice as high as would DSI. These commenters argue that the DSI. Sodium bicarbonate is more actually be needed in practice for sector will need to retrofit many more reactive with acid gases than trona. It certain applications. It is apparent that FGD scrubbers than projected by IPM would require less tonnage of sorbent if EPA were to re-analyze MATS for MATS compliance and will therefore and less tonnage of waste disposal than compliance with DSI injection rates experience a much higher overall cost of trona for the same SO2 removal effect, reduced by 50 percent, there would be compliance than projected by IPM, as albeit at somewhat higher sorbent cost. a corresponding reduction in the well as needing more time and Non-sodium based sorbents such as sorbent and related waste disposal costs resources for retrofit construction. A few hydrated lime (calcium based) could that constitute most of the cost of using also be used. Therefore, EPA’s modeling commenters suggested that EPA should DSI. of DSI technology does not include the base its MATS modeling on this more Given the EERC test data, it is also full spectrum of sorbent choices that conservative outlook. A few apparent that most units that have ESPs real-world applications enjoy, meaning commenters were concerned that EPA’s and are burning low sulfur western coal that there may be opportunities for DSI modeling assumptions relied on could meet the HCl limit using DSI lower-cost applications of DSI that are performance data from only one DSI without the addition of a FF. If EPA not captured in EPA’s projections for vendor. were to re-analyze MATS compliance MATS. The EPA models DSI with trona Some commenters were concerned while allowing DSI use without the injection rates corresponding to 70 that fly ash currently sold for beneficial need for a downstream FF, it is apparent percent SO removal for all coals, uses will become unsalable because it 2 that there would be a very significant assuming that an equivalent amount of will be contaminated by injected reduction in the overall number of FF sorbent is needed to provide 90 percent sodium-based DSI sorbents. Two retrofits projected, and a corresponding HCl removal, regardless of the low commenters argued that EPA’s IPM reduction in annualized capital costs. sulfur and chlorine content of western analysis understates DSI cost by not For the MATS proposal, the EPA coals. modeled DSI on the assumption that all including the costs of foregone fly ash Senior technical staff from the EPA chlorine in coal converts to HCl, and sales revenue and contaminated fly ash have carefully evaluated the key that DSI would be the only mechanism disposal. A few commenters observed assumptions regarding the cost and by which the unit could prevent HCl that landfilling of sodium-based DSI operation of emission control from being emitted. Based on public solid wastes will produce leachate technologies. In general, these staff believe that trona should have strong 339 Solvay Chemicals, Inc., HCl Removal in the 336 Dominion Energy, BART Analysis for the Presence of SO2 Using Dry Sodium Sorbent Kincaid Power Plant, January 2009, http:// HCl reaction selectivity and, consequently, EPA’s assumed trona Injection, http://www.solvair.us/SiteCollection www.epa.state.il.us/air/drafts/regional-haze/bart- Documents/presentations/20111214_hcl_ kincaid.pdf. injection rates may be overstated. The presentation.pdf. 337 Dry Sorbent Injection Systems for Acid Gas extent to which this assumption may 340 United Conveyor Corporation, Dry Sorbent Control, Babcock & Wilcox, 2010, http:// actually overstate DSI control costs can Injection for Simultaneous SO2, HCl, and Hg www.babcock.com/library/pdf/ps-451.pdf. be observed through DSI pilot testing for Removal, October 2011, http://unitedconveyor.com/ 338 Technologies for Acid Gas Control, Babcck & uploadedFiles/Systems/Systems_Sub/ Wilcox, 2011, http://www.babcock.com/library/pdf/ Solvay Chemicals by the Energy & McIlvaine%20Multipollutant%20Removal ps-457.pdf. Environmental Research Center (EERC) %20Oct%202011.pdf.

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comments and a more thorough review prepared for EPA (see proposal IPM at most a small increase in production of the ICR data, the EPA has introduced documentation in the docket). The EPA capacity. in final MATS modeling a recognition has continued to model DSI at this For all of these reasons, the EPA that the relatively high alkalinity of ash waste disposal cost for analysis of the believes that its representation of DSI in from subbituminous and lignite coals final rule. However, recent discussions MATS compliance modeling is ‘‘removes’’ much of the HCl that would between senior technical staff from the reasonable, is properly limited to otherwise be emitted from combustion DOE and the EPA have suggested that in applications that are technically of these particular coals. The 2010 ICR some situations sodium sulfates, that feasible, and reflects a conservative data indicate that in some cases the ash would be formed by the injection of approach to modeling future use of this itself removes sufficient HCl from these trona, could potentially leach out of the technology. coals for MATS compliance; in effect, fly ash/sorbent mixture on contact with 2. Economic Hardship these acid-gas emissions are absorbed by water. Although the technical staff coal ash and are captured by particulate recognized that these concerns are more a. Job Losses and Economic Impacts control devices instead of being emitted relevant to bituminous coal-fired units Comment: Several commenters in gaseous form. As a conservative where ashes are not cementitious, indicated that they believe the proposed measure, EPA’s revised final MATS unless mixed with limestone or lime, rule will weaken industry, cause job modeling assumes that 75 percent of they suggested that the impacts of losses and hurt power consumers. One HCl is removed by the ash for these potentially higher disposal costs be commenter reported that the proposed coals. In the event that ash capture in evaluated. Based on public comments, rule will affect 1,350 coal and oil-fired practice is more effective than this 75 further investigations by Sargent & units at 525 power plants and that percent assumption, then EPA’s analysis Lundy, and suggestions from the EPA NERC reports that by 2018 nearly 50,000 projects a conservatively higher level of and DOE technical staff, EPA’s analysis MW of capacity will be retired by the DSI installations (and, thus, compliance of the final rule has included an IPM proposed rule. Many of these cost) than would actually occur in sensitivity case using a DSI waste commenters compared the cost practice. In any case, it appears that disposal cost of $100/ton. The estimated by EPA to a variety of other significantly less sorbent injection sensitivity case indicates that a 100 sources that estimate substantially would actually be required in practice percent increase in assumed DSI waste higher costs of the rule. The than assumed by EPA for these low disposal cost produces slightly less than commenters expressed concern that sulfur, low chlorine coals, and that the a 1 percent increase in the projected electricity price increases are likely to IPM projected DSI operating costs are cost of the rule. be up to 24 percent in some regions as likewise higher for these coals than a result of the proposed rule. In addition would be experienced in practice. Comment: A few commenters The EPA models DSI with sorbent expressed the concern that there is an to the economic difficulty the proposed injection occurring downstream of an inadequate supply of trona to support rule could place on consumers, the existing electrostatic precipitator (ESP). DSI operations at the levels projected by commenter believes that many in the The existing ESP is assumed to remain the EPA for MATS compliance. energy sector will lose their jobs due to in service. The model adds a fabric filter Response: The EPA projects that just coal-fired capacity losses. The downstream of the DSI injection point over 50 GW of coal-fired capacity might commenters believe the effects on coal- to capture the small amount of PM retrofit with DSI for MATS compliance, fired plants in the Southeast especially will mean the loss of high-paying, high- passing through the ESP plus the thus reducing SO2 emissions by about 1 reacted and unreacted DSI sorbent. Most million tons per year. Based on skilled jobs and drastic price increases of the DSI projected by IPM, therefore, conservatively high trona injection in energy costs. Additionally, includes the costs of a retrofitted FF. rates, as discussed above, the EPA commenters expressed concern that This modeled configuration allows fly estimates that the amount of trona increased electricity and natural gas ash currently captured in ESPs to required to support DSI operations at prices would impact businesses in remain uncontaminated by DSI sorbent this level is about 4 million tons per multiple sectors across the country. and, therefore, remain available for sale year. By comparison, the trona mining Response: The EPA disagrees with the and beneficial use. The EPA industry in the U.S. has a demonstrated estimates presented by the commenters. conservatively models FF costs based on production capacity of at least 18 The EPA has updated its analysis to an assumed full-size system with an air- million tons annually, and was running reflect the final MATS. The Agency to-cloth ratio of 4.0. The FF costs could well below that capacity (16.5 million estimates the annual costs of the final be somewhat less in practice if a smaller tons) in 2010.342 343 If the EPA’s rule in 2015 to be $9.6 billion in 2007 system (with an air-to-cloth ratio of 6.0) assumed trona injection rates are as dollars. The estimate of early were used for the reduced DSI dust much as 50 percent greater than actually retirements of coal-fired units due to loading. The EPA observes that some of needed for at least 90 percent HCl this rule is 4.7 GW, lower than the level the owners of units with ESPs may control, as discussed above, and given estimated at proposal. Both of these chose to convert existing ESPs into that some subbituminous coals will estimates were prepared using the IPM, FFs,341 an option not modeled in IPM, apparently need little or no sorbent a model that has been extensively but that would likely have a lower injection for HCl control, there may reviewed and has been utilized in capital cost than a retrofitted FF. In the already be an adequate surplus of trona several rulemakings affecting the power MATS proposal EPA modeled DSI with production capacity to support DSI for generation sector over the last 15 years. a waste disposal cost of $50/ton, based MATS compliance. The EPA, therefore, The Agency’s analyses are credible and on a Sargent & Lundy DSI cost model concludes that trona supply for DSI is accurate to the extent possible, and all either already adequate, or will require assumptions and data are made public. 341 TW Lugar, et al., The Ultimate ESP Rebuild: Limitations and caveats to these Casing Conversion To a Pulse Jet Fabric Filter, a analyses can be found in the RIA for this Case Study, Electric Power Conference, May 2009, 342 http://www.wma-minelife.com/trona/ http://www.cecoenviro.com/uploads/ tronmine/tronmine.htm. rule. ESP%20to%20Fabric%20Filter%20Baghouse%20 343 http://www.wma-minelife.com/trona/ The EPA estimates that there will be Conversion%20-%20Buell%20Case%20History.pdf. TronaPage2/trona_production.htm. an increase of 3.1 percent in retail

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electricity price on average in the 30,000 net jobs gained on an annual 2015 to 2.0 percent in 2020 as shown in contiguous U.S. in 2015 as an outcome basis.348 See Chapter 6 of the RIA for Chapter 3 of the RIA. of this rule, with the range of increases further details. Despite the absence of a satisfactory from 1.3 percent to 6.3 percent in The EPA has also looked at the methodology for quantifying the regions throughout the U.S. No region of possibility that changes in the price of potential economy-wide effects the U.S. is expected to experience a electricity may influence the levels and (including employment) of any potential double-digit increase in retail electricity geographic distribution of downstream increases in electricity prices resulting prices in 2015 or in any year later than economic activities, and associated from this rule, the EPA expects the that, according to the Agency’s analysis, employment. Projecting how potentially incremental effects of this rule on as a result of this rule. To put this in higher electricity prices may affect electricity prices to be small given the context, the roughly 3 percent various downstream economic activities projected electricity price increases incremental increase in aggregate end- in particular regions as a result of this relative to historical levels and volatility user electricity prices projected to occur rule is challenging for several reasons: in end-user electricity prices. Based on over the next 4 years is about the same (1) There are significant uncertainties these projections and contextual as the 3 percent absolute average change regarding projections of consumer- and information, the Agency believes that in total end-user electricity prices location-specific electricity price the incremental effects on electricity observed on an annual basis.344 changes in response to future firm- prices and economic activity of this rule Furthermore, the roughly 3 percent specific compliance strategies; (2) the are likely to be small relative to other incremental price effect of this rule is availability of competitively-priced factors influencing electricity prices, small relative to the changes observed in alternative energy sources (including overall employment, and other aspects the absolute levels of electricity prices energy conservation) and less of economic activity. over the last 50 years, which have electricity-intensive substitute goods Comment: Several commenters ranged from as much as 23 percent and services may significantly mitigate considered the proposed rule to be a tax lower (in 1969) to as much as 23 percent potentially adverse economic on the American public, since utilities higher (in 1982) than prices observed in consequences resulting from projected implementing upgrades will pass the 2010.345 Even with this rule in effect, increases in electricity prices in ways costs on to the consumer. Commenters electricity prices are projected to be which are not captured effectively in questioned the preference of Americans lower in 2015 and 2020 than they were currently available models; and (3) to subsidize renewable energy sources in 2010.346 available modeling tools are not and put money into the proposed rule The Agency found that the readily configured to capture the effects over instead of other environmental discernible impact on long-term time of economically significant effects programs with greater benefits. Commenters explained that the tax-like employment nationally within the most of cleaner air (e.g., reductions in price increase reduces income of energy directly affected sectors should be small medical expenditures and consumers and depresses business and the EPA also estimated that about improvements in labor productivity development. The commenters used 46,000 job-years 347 of one-time resulting from fewer lost work days) California as an example of a state that construction labor could be supported achieved by rules evaluated using single uses low rates of coal-based electricity or created by this rule. This includes target year criteria pollutant and/or HAP and cites companies that have left the jobs manufacturing steel, cement and benefits projections. After considering state as a result of substituting higher other materials needed to build these methodological limitations, the Agency concludes that there is not a cost forms of electricity for coal. A pollution control equipment, jobs satisfactory methodology for projecting commenter stated that coal-derived creating and assembling pollution the downstream economic (including energy will rapidly become more control equipment, and jobs installing employment) effects of any changes in expensive, especially in the ‘‘rust belt’’ the equipment at power plants. electricity prices due to this rule. and Southeast region, as can be seen by Potential job increases from increased We expect the downstream economic the rate increase already requested in output by lower-emitting facilities (such effects of this rule to be small because Louisville. A commenter believes the as increased generation from well- electricity is only a small factor in the ‘‘indirect taxation’’ limits the ability of controlled coal-fired plants that replace production of most goods and the economy to absorb the cost of generation from older coal-fired plants) services.349 A 3 percent increase in end- retrofitting and new capacity projects, are expected to partially or fully offset user electricity prices translates to a lowers discretionary spending and leads potential job losses resulting from much smaller effect on prices and to job losses and lost tax revenues, given reduced output from higher-emitting potential output of goods and services the restrictive timeframe for facilities. The EPA analysis projects a from end-users of electricity. Over time, compliance. net change in the directly affected EGU the incremental effect of this rule on Response: The Agency does not agree sector of between 15,000 net jobs lost to electricity prices is projected to that this rule creates or alters any taxes diminish significantly; for example the on affected sources required under this 344 EIA Annual Energy Outlook 2010 annual total rule to reduce their emissions of toxic electricity prices from 1960 to 2010, Table 8–10. difference in expected prices is 345 Ibid, EIA AEO 2010, Table 8–10. projected to narrow from 3.1 percent in air pollutants, nor are taxes created or 346 Ibid, EIA AEO 2010, Table 8–10 for price altered or imposed on consumers of levels; and Chapter 3 of the RIA for electricity price 348 It should be noted that if more labor must be electricity which is provided to the differential. used to produce a given amount of output, then this market by affected sources. Moreover, 347 A ‘‘job-year’’ is a combined measure of jobs implies a decrease in labor productivity. A decrease unlike a tax, this rule does not generate and job duration which is equivalent to one person in labor productivity will cause a short-run being employed for one year. For example, 2 job- aggregate supply curve to shift to the left, and government revenue. The rule does, years could represent two years of employment for businesses will produce less, all other things being however, indirectly address the problem one worker, one year of employment for two equal. of the ‘‘externality cost’’ of higher health workers, or 6 months of employment for four 349 BEA. (2007b). Commodity-by-Industry Direct risks and other adverse effects on the workers. Estimates of employment changes that Requirements after Redefinitions, 2002. Available involve non-permanent workers are usually in: 2002 Summary Tables, 2002 Benchmark Input- populations exposed to toxic air reported in job years to give a sense of the total Output Data. Retrieved from http://www.bea.gov/ pollution emissions from affected employment effects. industry/io_benchmark.htm#2002data. sources. This rule may have the effect of

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reducing or eliminating a market competitiveness of U.S. workers due to which confirm this finding and state distortion that provides an implicit reduction in work days lost to air that the analysis underestimates the subsidy to affected facilities. This pollution-related illness. The benefits of rule’s net benefits and positive impacts implicit subsidy results from the fact these improvements are projected to on the nation’s economy. By that some facilities currently can avoid exceed costs of compliance by affected considering some benefits not the costs of toxic air pollution controls sources by at least six-fold. The monetized in the EPA analysis, Dr. by imposing higher health and other potential price increases in electricity Cicchetti concludes that the proposed costs on those who are exposed to and natural gas should be considered in rule will create $52.5 to $139.5 billion higher levels of toxic air pollution. The light of the substantial health, welfare, in net benefits annually, create 115,200 Agency also disagrees with the and economic benefits achieved by this jobs, generate annual health savings of implication that the costs incurred by rule. $4.513 billion, annual increases in GDP less-controlled sources to bring their Comment: Many commenters of $7.17 billion and $2.689 billion in toxic air emissions in line with their expressed support for the EPA’s impact additional annual tax revenues, and better-controlled competitors will lead analysis and disputed claims by other spur innovation and modernization of to significant or debilitating changes in commenters that the projected rule will EGUs. The commenters state that the market and economic conditions. The harm economic growth. A number of study findings show no need to delay Agency’s estimate of the potential commenters mentioned testimonials by implementation of the rule or needlessly increase in retail electricity price is an power company CEOs stating that the duplicate economic analyses already average of 3.1 percent in 2015, with a proposed rule will not affect the completed. range of increases by region from 1.3 economic health of the industry and a Commenters reported that multiple percent to 6.3 percent. As shown in survey showing nearly 60 percent of the researchers confirmed that the EPA’s Chapter 3 of the RIA, the higher rates of coal-fired units already comply with the estimates of economic stimulus are potential electricity price increase tend EPA’s proposed Hg standard, and conservative and that the proposed rule to occur in those regions where several other meaningful quotes from will stimulate job growth. A commenter electricity prices have been relatively utility executives. The commenters also quotes Dr. Josh Bivens of the Economic low, due to some extent to reliance on pointed out that 17 states already Policy Institute, who also found that coal-fired units which have been require plants to address Hg pollution, EPA’s conclusions were conservative. cheaper to operate due to with some imposing more stringent Dr. Bivens concluded, ‘‘The EPA RIA on underinvestment in toxic air pollution emission limits than the EPA proposes. the proposed toxics rule makes a controls.350 As shown in Chapter 3 of The commenters believe that utilities compelling case that the rule passes any the RIA, all regions with year 2015 use the threat of power plant closures reasonable cost-benefit analysis with projected percentage increases in retail and lost jobs to delay Hg reductions flying colors—the monetized benefits of electricity prices above the contiguous from coal-fired plants. Commenters also longer lives, better health, and greater U.S. average are also projected to have believe that the rules will drive productivity dwarf the projected costs of baseline retail electricity prices which innovation and job creation as new compliance * * * Whether regulation are below the contiguous U.S. average technologies to reduce pollution are in general and the toxics rule in price level in that year. In addition, created. Several commenters quoted the particular costs jobs is an empirical natural gas prices will only increase by Economic Policy Institute finding that question this paper attempts to answer. 0.3 to 0.6 percent on average over the the proposed rule will increase job In particular, this paper examines the time horizon of 2015 to 2030. As growth by 28,000 to 158,000 jobs by possible channels through which the discussed above, for consumers of 2015 (including approximately 56,000 proposed toxics rule could affect electricity in the commercial and direct jobs and 35,000 indirect jobs), the employment in the United States and industrial sectors, electricity tends to be University of Massachusetts study that finds that claims that this regulation a fairly small fraction of total costs of showed an increase 1.4 million jobs in destroys jobs are flat wrong: ‘‘The jobs- production, implying that the average 5 years, and the Constellation Energy impact of the rule will be modest, but projected electricity price increase of 3 Group installation project that it will be positive.’’ His report details percent will lead to only a small employed nearly 1,400 skilled workers. the following major findings: fractional change in the costs of Commenters also cited the University of 1. The proposed rule would have a providing goods and services to the Massachusetts study statement that a modest positive net impact on overall economy. While some residential net gain of over 4,200 long-term employment, likely leading to the electricity consumers may similarly see operation and maintenance jobs will creation of 28,000 to 158,000 jobs a small price increase in retail result. between now and 2015. electricity prices, it should be noted that Several commenters observed that the 2. The employment effect of the these consumers tend to reside in the positive impacts of the rule strongly [MATS] on the utility industry itself same area or region as the affected favor its adoption. These commenters could range from 17,000 jobs lost to facility and so will also experience the stated that, contrary to the unfounded 35,000 jobs gained. improvement in air quality from the assertions by critics of EPA and the rule, 3. The proposed rule would create reductions due to the rule. The EPA has conducted a technically sound between 81,000 and 101,000 jobs in the reduction in health risk and other and conservative benefit-cost analysis pollution abatement and control improvements to quality of life showing that the proposed rule’s industry (which includes suppliers such associated with lower exposure to toxic estimated benefits are at least five times as steelmakers). and other air pollutants achieved by this as high as its costs. One commenter 4. Between 31,000 and 46,000 jobs rule will confer benefits on these stated, ‘‘With sound, albeit unduly would be lost due to higher energy consumers which include lower risks of conservative, econometric modeling, prices leading to reductions in output. premature mortality, lower morbidity, EPA has also determined that the Toxics 5. Assuming a re-spending multiplier and improved productivity and Rule will promote economic growth and of 0.5, and since the net impact of the create jobs in both the long and short above impacts is positive, another 9,000 350 http://www.epa.gov/airmarkets/images/ term.’’ Two commenters cited the EPA to 53,000 jobs would be created through CoalControls.pdf. impact analyses by Dr. Charles Cicchetti re-spending.

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Response: The EPA thanks the c. State or Regional Impacts Appalachia, the Midwest and Rocky commenters for these observations. The Comment: Multiple commenters Mountain West will be significantly Agency’s estimates of employment expressed concern over the impact of affected by the proposed rule, including impacts, found in the RIA for the rule, the rule on electricity prices and increased unemployment. Other are smaller than those identified by the reliability in specific states or regions. commenters stated that communities some commenters, though the EPA uses These commenters were concerned that near existing coal-fired generation units a different methodology that focuses on these impacts would adversely affect will be especially hard-hit if the plants impacts specific to the electric power specific industries such as construction are permanently retired. The sector. and manufacturing. One commenter communities will suffer from job loss suggested the EPA consider regional and diminished tax revenue. b. Impacts on Low-Income Consumers differences that will impact system Response: The Agency’s analysis, as reliability and costs, such as the found in the RIA, shows that impacts to Comment: Commenters expressed these regions are mixed. For concern that the EPA’s overview of the increased impacts on regions relying heavily on coal and oil and encourages Appalachia, coal production is price increases does not consider the projected to fall by 6 percent in 2015, hardships that will be the reality of cooperation between the EPA and state and federal energy and environmental while the Western coal producing increased prices on low-income or regulators. region will experience a decrease of 3 fixed-income households or small Response: The Agency has studied percent in production in 2015. The businesses. The commenter reports possible impacts on resource adequacy Interior region is projected to see a 9 increases of $90 million in capital costs, as a result of this rule, and has percent increase in production. Retail $11.4 million in annual operating costs determined that these impacts should electricity prices are expected to and $6.4 million in annual debt service not be significant. Furthermore, increase by 1.3 percent to 6.3 percent in costs to achieve compliance, which will industry, along with relevant federal various parts of the country in 2015. lead to a 13 percent increase in rates for agencies, has the tools needed to Also, the estimated number of early the proposed rule, and a 41 percent address any reliability concerns. The retirements according to the Agency that increase for all proposed and new Agency has prepared an updated may result from this rule is 4.7 GW in regulation compliance costs. The feasibility TSD in support of the final 2015, or less than 2 percent of all U.S. commenter argues against the EPA’s rule, which is in the docket for this coal-fired capacity in that year. Thus, view that energy efficiencies will offset rulemaking.352 The Agency has there may be some negative impacts rate increases, because low income considered impacts on a regional basis from this rule in some regions, but these customers will need to use less as part of its overall analyses done using same regions will also experience some of the benefits, such as reduced electricity due to economic necessity. the IPM; these results are documented premature mortality from less exposure The commenter also sees large price in the RIA for the rule and in the feasibility TSD. to PM2.5 emissions as shown in Chapter increases for customers if units are 5 of the RIA. As discussed previously, converted to natural gas, which is The EPA’s analysis shows that retail electricity price increases will not fall the EPA’s analysis shows that retail approximately 2.5 times more expensive electricity price increases will not fall than the coal that the commenter disproportionately on a specific region. In fact, those regions experiencing the disproportionately on a specific region. currently uses to generate electricity. largest change in prices are projected to In fact, those regions experiencing the Response: The EPA’s estimates of have retail electricity prices below the largest change in prices are projected to increase, relative to the baseline, in the national average both in the absence of have retail electricity prices below the retail electricity price range from 1.3 MATS and after the implementation of national average both in the absence of percent to 6.3 percent regionally in MATS. In Chapter 3 of the RIA, the EPA MATS and after the implementation of 2015, with an average increase presents retail electricity prices by MATS. nationwide of 3.1 percent in 2015. Low- region in 2015, for both the base case The results of the EPA’s employment income households will thus see some and MATS policy case. The six regions analysis, found in Chapter 6 of the RIA, increase in electricity price, but this that are projected to have retail indicate that the final MATS has the increase should be modest. In addition, electricity prices above the national potential to provide significant short- term employment opportunities, the increase in the price of natural gas average price in 2015 in the absence of primarily driven by the high demand for as a result of this rule is expected to be MATS are projected to have increases that are below the national average new pollution control equipment. While 0.3 to 0.6 percent over a time horizon the employment gains related to the of 2015 to 2030. This increase in price increase following the implementation of MATS. Those regions that have new pollution controls are likely to be is low enough that electricity customers tempered by some losses due to certain should not experience a major increase projected retail electricity price increases that are above the national coal retirements, some of these workers in price resulting from any modest who lose their jobs due to plant changes to electricity generated by average are all projected to have retail electricity prices below the national retirements could find replacement natural gas. The roughly 3 percent employment operating the new incremental price effect of this rule is average in the absence of MATS. Comment: A commenter quoted pollution controls at nearby units. small relative to the changes observed in National Mining Association statistics Finally, job losses due to reduced coal the absolute levels of electricity prices showing coal is responsible for $65.738 demand are expected to be offset by job over the last 50 years, which have billion in annual economic activity, gains due to increased natural gas ranged from as much as 23 percent produces 1,798,800 jobs and $36.345 demand, resulting in a small positive lower (in 1969) to as much as 23 percent billion in annual labor income. The net change in employment due to fuel higher (in 1982) than prices observed in commenter reports that regions such as demand changes. 2010.351 While shifts in employment are 352 See ‘‘An Assessment of the Feasibility of difficult for those directly affected, and 351 EIA Annual Energy Outlook 2010 annual total Retrofits for the Mercury and Air Toxics Standards the Agency remains concerned about electricity prices from 1960 to 2010, Table 8–10. Rule’’ in the docket. the challenges job shifts can bring to the

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individuals affected, Bureau of Labor support the finding that over 50 percent option of an input or output standard Statistics data indicate that compliance of the fleet is equipped with scrubbers for existing units, and allowing for with pollution control requirements is a and the number will increase to nearly alternative compliance options (e.g., for relatively very small contributor to 2⁄3 by 2015. coal, filterable PM or total non-mercury overall employment shifts in the U.S. Response: The EPA agrees with the metallic HAP or individual HAP economy. Specifically, the main cause findings of the independent studies metals). In addition, the Agency is not of mass layoffs over the last four years mentioned by the commenter. prescribing specific technologies as part according to 2007 to 2011 Bureau of e. Impacts on Mining of this final rule, but instead requiring Labor Statistics data is ‘‘lack of business emissions limitations be met. This demand,’’ accounting for over 40 Comment: Multiple commenters approach allows the industry to find the percent of the layoffs reported by mention the proposed rule’s impact on most cost-effective approach to meeting industry. In contrast, all types of mining. One commenter mentioned the requirements while ensuring regulatory actions (including health, increasing energy costs for the U.S. considerable public health benefits. safety, and environmental) by all levels mining industry, resulting in fewer of government (Federal, State, local) projects and associated jobs, as well as g. Temporary vs. Permanent Jobs combined were cited as the primary increasing dependence on foreign Comment: A commenter expressed factor in only 0.2 percent of mass layoffs mineral resources. Commenters see disagreement with the EPA prediction over the same period.353 mining impacts being disproportionally of new jobs created, because the large for lignite mines, which are commenter believes far more plants will d. Retirements of Coal-Fired EGUs and dependent on their co-located lignite- Shutdowns shut down than the EPA predicts, fired power plants. The commenters resulting in higher job losses. The Comment: A commenter discussed state that if the plant closes, there is no commenter also pointed out that while the economic factors behind EGU market for the lignite and the mine will jobs running power plants are retirements. These factors include the also close, displacing plant workers. permanent, the jobs predicted to be cost of alternative generation using These impacts are largest in Texas, the created by the proposed rule are short natural gas, the cost of implementing largest coal consuming state and fifth term construction jobs, and will all demand response measures that can be largest coal producing state, as well as occur in the same short timeframe for bid into capacity markets, and the cost a deregulated electricity market. One compliance. The commenter also stated of continuing to generate power from an commenter pointed out that the Texas that the EPA estimate does not include existing unit. The commenter states that coal market provided a buffer against the opportunity cost of lost construction regardless of the costs associated with natural gas price volatility and in jobs due to new power plants that will the Toxics Rule and other EPA electric particular believes the proposed rule not be constructed due to the proposed power industry regulations, some power does not take into account the emission rules. reductions already achieved by industry plants were already economically Response: The Agency believes that in general and their company in unsustainable. The commenter quotes the employment impacts of the final particular. A commenter stated that M.J. Bradley, who points out, ‘‘[o]f the rule will be small, as has been the case impacts will be magnified in Texas, 122 coal units in PJM with capacity less historically with regards to since it is the largest coal consuming than or equal to 200 MW, 35 failed to environmental regulation. The Agency state and mines lignite. A commenter recover their avoidable costs and does provide an estimate of the long- indicated they believe it is unclear the another 52 were close to not recovering term employment impacts to the electric extent to which EPA includes the those costs. Therefore, in PJM * * * in power sector in the RIA for the rule, and impacts on the mining industry that will addition to approximately 10 GW of that estimate shows a range of impacts result from this rule. coal generation that has or will be from 15,000 net jobs lost to 30,000 net retired during the 7 years from 2004 to Response: The Agency presents impacts on the coal mining sector from jobs gained (all annual), but also 2011, another 11 GW faces a troubling recognizes important limitations to economic outlook.’’ The commenter this rule in the RIA. Given the modest increase in coal and other energy costs these estimates. The Agency’s estimate provides confirmation of this by the of impacts to short-term jobs, including most recent PJM capacity auction, associated with the rule, the Agency does not expect widespread impacts on those in construction, accounts for both where approximately 6.9 fewer GW of losses and gains that result from the coal-fired capacity cleared the auction coal mining. The Agency’s modeling accounts for all emission controls and rule. This is shown in Chapter 6 of the (1.85 fewer GW were offered) as RIA. compared with the prior year’s auction, programs installed and/or implemented Comment: Commenters believe that and an additional 4.836 GW of new up through December 2010, including installation of new pollution controls demand response (energy efficiency) those in Texas. would be a job-growth opportunity in resources cleared the auction. Thus, the f. Flexible Regulations their states because money spent on commenter states, some claims linking controls for power plants creates high- retirements to the MATS are overstated Comment: Several commenters quality jobs in steel, cement and other and misleading. The commenter gives expressed concern over the potential materials, as well as in the assembling the example of the American Electric impacts of the regulation and believe of the equipment as well as installing Power attempt to link its planned plant that the requirements should be more and operating it. A commenter shares closures to the MATS, but those plants flexible in order to mitigate these the Alabama Fisheries Association already are slated to either close or to impacts. Response: The EPA believes the estimate that the water-based recreation upgrade controls to comply with requirements of the final rule have been industry brings in over $1 billion per existing laws. The commenter goes on to made as flexible as possible consistent year to the state’s economy though the quote three independent studies that with the CAA. The final rule allows state ranks third for imperiled fish with 61 bodies of water cited for Hg 353 U.S. Bureau of Labor Statistics, 2011. some flexibility, including allowing Extended Mass Layoffs in 2010. http://www.bls.gov/ averaging across units in the same contamination. The commenter believes mls/mlsreport1038.pdf. subcategory at a facility, allowing for an the HAP accumulating in the waterways

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threatens the industry with permanent Response: The Agency has fully Response: The Agency has addressed job-losses and lost revenue. documented its assumptions and concerns with the feasibility and timing Response: The Agency agrees with the framework for modeling natural gas in of control installations in its report on commenter that the reduction in HAP IPM for both the proposed and final the subject (see feasibility TSD that will take place as a result of the rule MATS. This information can be found contained in the docket for this rule). over time will help to improve in Chapter 10 of the IPM documentation Comment: Multiple commenters do waterways in Alabama and thus help (http://www.epa.gov/airmarkets/ not believe that labor availability will the water-based recreation in that state. progsregs/epa-ipm/docs/v410/ constrain control installation in the More information on the benefits of Hg Chapter10.pdf). The documentation required timeframe and cites an and other HAP reductions can be found provides a thorough overview of the Institute of Clean Air Companies (ICAC) in Chapter 4 of the RIA for the rule. The natural gas module, describes the very response that it will not for these Agency also agrees with the commenter detailed process-engineering model and reasons: that the addition of control equipment data sources used to characterize North 1. The power sector has demonstrated for EGUs may stimulate employment in American conventional, ability to install large number of systems a variety of industries. unconventional, and frontier natural gas in short time period; resources and reserves and to derive all 2. The majority of coal plans have h. Natural Gas the cost components incurred in installed control systems already; Comment: A commenter states that bringing natural gas from the ground to 3. Fewer resource and labor-intensive natural gas use is only an option in the pipeline. Also documented are the control options being used for places where infrastructure exists to resource constraints, liquefied natural compliance; and supply sufficient natural gas to the EGU gas (LNG), demand side issues, the 4. End users have utilized cost and other local needs and reports that natural gas pipeline network and reducing and implementation efficiency year-round reliable gas delivery is rare capacity, procedures used to capture strategies for efficient deployment of due to requirements to meet the other pipeline transportation costs, natural technologies. needs. The commenter says that gas gas storage, oil and natural gas liquids Another commenter states that a wide interruptions are prevalent in the (NGL) assumptions, and key gas market range of technical and economically winter, but can happen year-round, and parameters. feasible practices and technologies are the costs of establishing a natural gas i. Compliance Timeline and General available currently to meet the emission line to a power plant can be tens of Timeline limits and are in use around the millions of dollars or more, and moving country. a plant to a gas source can take many Comment: A commenter states that Response: These comments are years. The commenter describes the the proposed rule will require costs be generally consistent with the options for a Norwalk Harbor plant, and passed on to consumers, meaning state conclusions of the Agency’s analyses on explains that the modifications are public utility commissions will be feasibility of control installations for costly and difficult even before flooded with requests for rate increases this rule as found in the feasibility TSD considering the modifications needed to from utilities trying to recover in the docket for this rulemaking. alter the boiler and fuel supply system expenditures. The short deadline will to allow natural gas combustion. also result in a large number of j. Burden Outweighs Environmental Response: The final rule does not extension requests made to state Gain prescribe either pollution control permitting authorities, further Comment: Several commenters state technologies to be used, nor does it burdening them. that the EPA has no data relating to dictate the types of fuels that should be Response: The compliance date for benefits from reducing non-mercury burned. The requirements of the final this rule for existing sources will be 3 HAP, so the costs of the proposed rule rule are designed to allow industry to years and 60 days after publication of exceed the HAP benefits by 29,000 find the most cost-effective approach to the final rule in the Federal Register, or times. One commenter states that the addressing harmful emissions that are approximately March 2015. Thus, there impact analysis was largely focused on covered by this action. The Agency will be some time before the impacts of Hg with little support for other HAP believes that cost-effective technologies this rule such as any increase in retail reductions and failed to provide account exist today and have been deployed on electricity prices become a concern. It of true costs and benefits. many power plants, and utilities will be also should be noted that increases in Response: While we are not able to able to find intelligent solutions to retail electricity prices will be 3.1 monetize the benefits from reductions of address harmful emissions. The EPA percent on average in 2015, with a range non-mercury HAP that will take place, has provided supporting information as regionally from 1.3 percent to 6.3 these important effects are discussed part of the preamble and RIA for this percent. qualitatively in Chapter 4 of the RIA. rule, along with the feasibility TSD, Comment: A commenter reports that The quantified benefits of this rule which demonstrate the availability and they will need to install add-on include the reductions in non-HAP performance of technologies to meet the pollution controls to meet the proposed emissions such as SO2 and PM2.5 that requirements of the final rule. emission standards as well as will occur as a co-benefit of this rule as Comment: A commenter discusses the implement other physical or operational modeled by EPA. The total benefits are factors that could lead to higher natural changes. The commenter expresses estimated to outweigh the total annual gas prices not currently reflected in the concern about the number of pre- costs of the rule by a margin of either EPA impact projections, including construction steps that would be 3 to 1 or 9 to 1, depending on the industrial load and demand not required, as well as the new benefits estimate and discount rate rebounding to 2008 levels and the construction activities and the used. These reductions are credible and influence of liquefied natural gas challenges of scheduling sequence are considerable in size. The estimates exports. The commenter asks that the relative to interconnections and other of these benefits reflect the latest EPA address a variety of factors related tie-in considerations involved in scientific understanding on the subject. to its natural gas assumptions. compliance. More information on the estimates and

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the methodology for their preparation regulations. In March 2011, EPA issued properly, and the Agency will continue can be found in the RIA for the rule. the Second Clean Air Act Prospective to do so in support of this final rule. Comment: Several commenters Report which assessed the benefits and Comment: A commenter states that consider the proposed rule to be the costs of regulations pursuant to the 1990 the reductions in SO2 and PM2.5 most expensive clean air rule ever. They Clean Air Act Amendments. The study required by the proposed rule will assist point out the estimated $10.9 billion examines the cumulative impact of state and local air pollution control annual cost in 2015 and approximate these regulations (found at http:// agencies to meet health-based air quality 1,200 existing coal-fired EGUs affected, www.epa.gov/air/sect812/feb11/ standards, reduce haze and improve both of which were estimated by the summaryreport.pdf). As shown in the visibility. The commenter points out EPA. Commenters believe the EPA’s report, the direct benefits from the 1990 that substantial reduction in emissions estimates are incorrect and the true cost Clean Air Act Amendments are made by the very large sources under will be far more, due to cumulative estimated to reach almost $2 trillion for the proposed rule will lead to fewer effects of all proposed power sector the year 2020, a figure that dwarfs the pollution controls needed at smaller rules, and indirect costs from job losses, direct costs of implementation ($65 sources to meet health-based ambient reduced productivity and billion). The full report is at http:// air requirements. This is a far more cost- competitiveness resulting from www.epa.gov/air/sect812/ effective approach than controls at electricity costs. They ask the EPA to prospective2.html. smaller facilities and is the lowest cost keep these high costs in mind when The direct benefits of the 1990 Clean path to improved public health and a evaluating impacts of the proposed rule Air Act Amendments and associated cleaner environment. and consider the costs with respect to programs are estimated to significantly Response: The EPA acknowledges the benefits. One commenter requests exceed their direct costs, which means that the HAP standards in this final rule that the EPA explain how its approach economic welfare and quality of life for will lead to considerable co-benefit utilized ‘‘the best available techniques Americans were improved by passage of reductions in PM and SO2. to quantify anticipated present and the 1990 Amendments. The wide l. Miscellaneous future benefits and costs as accurately as margin by which benefits are estimated possible’’ and includes analyses by EIA, to exceed costs, combined with Comment: A few commenters EEI, NERC, NERA, Credit Suisse, ICF, extensive uncertainty analysis, suggest discussed the impact of the rule on the and Burns & McDonnell. it is very unlikely this result would be federal budget deficit. One commenter Response: As noted earlier, the reversed using any reasonable points out that the proposed rule will Agency did not prepare a cumulative alternative assumptions or methods. affect the federal budget in two ways: impact analysis to accompany the rule 1. Direct compliance costs to electric The analysis presented in the RIA for for the following reasons: (1) The generating units (EGUs) owned by the current regulation uses a similar various EO requirements that the federal agencies; and methodology. Agency must comply with require us to 2. Pass-through compliance costs paid estimate impacts specific to this rule; (2) The techniques employed by the in the form of higher prices for decisionmakers and the public need to Agency for generating benefits and electricity purchased by federal know the impacts specific to a costs, and consider the most recent and agencies. particular rule in order to judge the complete data available to the Agency. Response: The Agency estimates the merits of the regulation; and (3) The EPA recognizes that the analyses direct compliance costs to EGUs that are estimates specific to a particular rule are have caveats and limitations, and we federally owned as part of the overall more transparent than those from a discuss our analyses and their caveats cost analysis completed for the proposal cumulative impact analysis. A and limitations in the RIA for the rule, and disclosed in the RIA for the rule. cumulative impact analysis lumps as well as in the benefits section of the The Agency does not provide an several regulations together and can preamble. The Agency has also revised estimate of the impact on federal potentially mask a high-cost/low benefit the cost analyses for the final rule to agencies from higher electricity prices regulation among other rules that may reflect data received in public associated with the rule, however. This have large net benefits. By analyzing comments on the proposed rule, and type of analysis is not required under each regulation separately, EPA makes costs are lower than when the rule was EO 12866 and statutory requirements. clear statements about the impacts, proposed. H. Testing and Monitoring costs, and benefits that are estimated as k. Impact on State Regulators a result of this particular regulation. Comment: Commenters raised This does not, however, mean EPA Comment: Several commenters numerous issues with the testing and has failed to incorporate these expressed concern over the burden monitoring requirements for initial and regulations into this analysis. The imposed on state regulatory agencies by continuous compliance. The following inclusion of CSAPR and other the rule. discussion highlights the comments and regulatory actions (including federal, Response: The Agency has estimated responses to a number of the critical state, and local actions) in the IPM base the costs of implementation of the rule issues and describe where the case reflects the level of controls that are to states that own EGUs affected by the comments have resulted in a significant likely to be in place in response to other rule, and has included this analysis in rule change or where we disagreed with requirements apart from MATS. This the RIA. The Agency has updated this commenters’ suggestions of issues or base case provides meaningful analysis for the final rule and it is need for changes in the rule. Additional projections of how the power sector will included in the RIA. While the EPA has comments and responses are addressed respond to the cumulative regulatory not prepared an analysis of the impacts in the Response to Comments document requirements for air emissions, while of the rule on state programs, the included in the docket for the final rule. isolating the incremental impacts of Agency does not believe the rule will be Test Methods. A number of MATS. These results are presented in unduly burdensome to the state commenters suggested that we should Chapter 3 of the RIA. regulatory agencies. The EPA works allow for the use of Method 5B to Additionally, the Agency does reflect closely with state regulatory authorities determine compliance with the PM on the cumulative impacts of our to ensure that the rules are implemented emission limit. In addition, a number of

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commenters objected to the frequency of quarterly emissions testing. Existing CFR part 60 and Procedure 2 in stack testing when used as the method solid or liquid fired units that qualify Appendix F to part 60. The EPA for demonstrating continuous for non-mercury LEE status will be provided this option in response to the compliance. Commenters also objected required to conduct a stack test every 3 comments in order to provide a to the requirement for testing one years, and neither fuel analysis nor straightforward direct measure of pollutant when the source was adherence to an operating limit will be compliance that some sources may want complying with an optional surrogate required. Should the stack test show to implement. (or vice versa); for example, commenters ineligibility for LEE status, the source Comment: Hg CEMS. Commenters objected to testing for HCl if a unit was will revert to using CEMS or PM CPMS raised a number of technical concerns complying with the optional SO2 limit, or conducting quarterly emissions about Hg CEMS. Many commenters or testing for metals if the unit was testing. requested modifications so that the complying with the optional PM limit. Comment: Operating Parameter requirements would be more consistent Response: Although Method 5B is Limits: Some commenters objected to with 40 CFR part 75 monitoring specified for wet scrubber-controlled the use of enforceable operating requirements. Some commenters utility boilers under 40 CFR part 60, parameter limits, requested that the rule questioned the ability of the technology subparts D, Da and Db, we are excluding be more consistent with the compliance to demonstrate compliance with Method 5B for demonstrating assurance monitoring program, and emission limits at very low levels compliance with the filterable PM raised specific objections to certain especially for new sources. Commenters emissions standard in this final rule. parameters required for certain control also opposed high data availability The extended high temperature heating devices. Commenters also raised requirements given that the technology of the filters prior to weighing as concerns about a PM CEMS operating is new and difficult to operate and specified in Method 5B would introduce limit establishing a de facto more maintain. differences between the compliance test stringent PM emission limit than the Response: We indicated in the data and the data that underlie the one being tested for under the total PM proposed rule the intent to adopt filterable particulate standard. Because standard in the proposal. CAMR-based requirements for Hg the test data that underlie and filterable Response: We believe that continuous monitoring in place of the general 40 particulate standard are based primarily monitoring in the form of CEMS, CFR part 63 performance specifications on Method 29 and Method 5 data sorbent trap monitoring systems, and and QA requirements. With CAMR, collected at 320 °F or comparable PM CPMS, or frequent stack emissions these operating and reporting filterable particulate methods, we are testing are appropriate to ensure requirements for Hg CEMS went specifying those same methods for ongoing compliance with this final rule. through notice and comment determining compliance with the We also agree with commenters that rulemaking for the same sources as standard. some of the monitoring provisions in covered by this final rule. Although For stack test frequency, we modified the proposal may have been duplicative CAMR was set aside on other grounds, the final rule to require quarterly testing and unnecessary. In order to provide these technical specifications and QA to demonstrate continuous compliance. flexibility in the final rule, we have requirements reflect significant input In addition, we agree that testing should retained a source’s ability to define an from stakeholders and analysis by the be required only for the emission limits operating limit and to monitor using a EPA to establish an appropriate that your source is complying with, and, PM CPMS as an option to periodic foundation for Hg monitoring at electric thus, the final rule does not require filterable PM emissions testing. utilities under the CAA. For the final testing of both the pollutant and the The final rule establishes the PM rule, we have made conforming changes surrogate. CPMS as an operating limit monitor and to ensure that this intent is carried out Comment: Fuel Analysis Methods. A not a direct filterable PM emission effectively throughout the rule text and number of commenters raised various monitoring requirement that meets PS Appendix A, as well as including concerns with the fuel analysis methods 11 requirements. Although we recognize certain additional clarifications based specified in the proposed rule. the importance of continued control on the input received in response to the Response: Based on the comments device performance to ensure emissions proposed rule. We have also removed a received and a further review of the minimization, we also are aware that cycle time test as unworkable for certain technical challenges associated with the other rules that apply to these units types of Hg CEMS. proposed fuel analysis requirements, we including, but not limited to, the The final rule provides the option for have not finalized the proposed fuel Operating Permits rule, the Compliance use of either Hg CEMS or sorbent trap analysis requirements. As the rule no Assurance Monitoring rule, the ARP monitoring systems. We believe the longer requires operating limits based rules, and the NSPS already require record clearly shows these to be proven on fuel content or fuel analysis, the continuous monitoring in most cases. technologies each providing certain comments on this issue are largely Those rules will remain in effect so the advantages. For existing and some of the moot. For LEEs, we agree that the need to impose additional operating new unit standards, the level of the proposed LEE ongoing eligibility limits monitoring or CEMS on those NIST-traceable Hg gas standards will be requirements were overly burdensome units is much reduced. adequate and consistent with existing and restrictive. As a result, existing The final rule also provides for the applications of Hg CEMS. For the lowest solid or liquid fired units that qualify use of a PM CEMS to determine limits and other applications where an for Hg LEE status will be required to compliance with the filterable PM integrated sampling system offers conduct a 30-day test for Hg using emission limit if the source elects to use advantages, affected facilities may opt to Method 30B each year. Neither fuel this approach. In that case, the PM use sorbent trap monitoring systems to analysis nor adherence to an operating CEMS is used as the direct method of comply. There are data in the recent limit will be required. Should an annual compliance and no additional testing is draft report entitled ‘‘Determining the test show ineligibility for LEE status, the required other than tests that are Variability Of CMMS At Low Hg source will revert to the requirements required as part of satisfying the Levels,’’354 that demonstrate reasonable for Hg monitoring using CEMS or requirements in Performance sorbent traps or, for oil-fired units, Specification 11 in Appendix B to 40 354 http://www.icci.org/reports/10Laudal6A-1.pdf.

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performance of at least one Hg CEMS at categories such as municipal waste for monitor downtime and establish an Hg levels below 1.0 microgram per combustors and EGUs. We have appropriate minimum data availability cubic meter (mg/m3) down to reviewed HCl CEMS vendor technology requirement. approximately 0.1 mg/m3. Finally, there claims and found sufficient capability to Response: We have attempted to is no specific minimum data availability support this rule requirement. We are harmonize the CEMS requirements in requirement for Hg CEMS (or any other engaged with representative this final rule with those under 40 CFR CMS required under this final rule). stakeholders to develop a generic part 75 wherever appropriate. One of This issue is discussed further below. performance specification for HCl CEMS those examples is the inclusion of Comment: SO2 CEMS: Although scheduled for completion in time to be conditional data validation for Hg commenters were generally supportive responsive to compliance with this rule. CEMS. We disagree that this final rule of the ability to use SO2 CEMS for units The final rule provides several needs a minimum data availability with FGD installed to demonstrate options for HCl and/or HF monitoring requirement. We have not included any compliance with an alternate SO2 including: specific minimum data availability emission limit instead of the HCl (1) Using Fourier Transform Infrared requirement for CEMS or other emission limit, there were some (FTIR)-based HCl CEMS and/or HF monitoring in this final rule nor do we concerns with aspects of the proposal. CEMS complying with Appendix B to provide a specific tool for data Commenters requested that the SO2 the rule which relies on PS 15, substitution. We believe that there are monitoring requirements rely on 40 CFR (2) Seeking approval for an alternative other provisions in the final rule to part 75 given that their sources were HCl monitoring procedure through 40 provide incentives to conduct already meeting those requirements and CFR 63.7(f), monitoring in a manner consistent with that this rule not establish any new (3) Monitoring compliance good air pollution control practices and requirements, especially a fourth continuously with the alternate SO2 to provide data sufficient to demonstrate linearity level and the application of 7- emission limit at coal-fired or other compliance with a relatively long-term day calibration error tests for units with solid fuel affected facilities equipped (30-boiler operating day) emissions rate low concentrations (where 40 CFR part with FGD technology for SO2, and limit. We agree that data quality 75 provides an exemption). Commenters (4) Quarterly reference method certainty associated with any calculated were also concerned that the rule testing. value decreases with the collection of language only allows the option where Including these options in the final less data such as would occur with the FGD is operated ‘‘at all times’’ rule provides flexibility to adopt CEMS extended periods of monitoring system which seems to imply that the option is monitoring options as the technology downtime. Even so, we believe also that not allowed if the source ever bypasses continues to mature and the new, non- it is necessary and critical for the FGD for start-up, shutdown, or technology-specific EPA performance compliance with the regulation that a malfunction reasons. specifications becomes available. source use all measured data collected Response: After reviewing the Comment: Bypass Stacks. Several during an averaging period to assess comments and assessing the need for an commenters raised concerns about the compliance regardless of any periods of additional calibration gas at the technical feasibility of monitoring missing data. Sources should not emissions limit, we have removed this bypass stacks with a CEMS. disqualify any data otherwise meeting requirement from the final rule while Response: We have modified the required data quality requirements retaining the requirement for a linearity bypass stack monitoring requirements. simply because there were data missing check even for SO2 monitors with low Under 40 CFR part 75, we allow the use for other hours or days of the averaging span values (≤ 30 ppm). A source can of a maximum potential concentration period. already report linearity tests for these value for reporting when emissions are Instead of a minimum data units within the context of the existing vented to a bypass stack. That approach availability threshold that would ECMPS reporting without triggering any works within the context of an invalidate data collected for some critical errors. This test can be emissions trading program, but is not averaging periods because one did not accommodated within the current appropriate when evaluating collect data for at least a specified framework without causing issues for 40 compliance with a specific emission percent of an averaging time, the final CFR part 75 reporting. The requirement limit. Thus, we have provided two other rule requires that a source report as for a 7-day calibration error test is options. One is to monitor the bypass deviations to the rule failure to collect removed. For the ‘‘at all times’’ stack, consistent with the final rule. The data during required periods if these language, we have clarified this in the other is to treat any hours of bypass deviations are not covered by final rule. The intent is that the FGD be stack emissions as periods of monitor exceptions allowed in the final rule. operated during all routine boiler downtime and hours of deviation from On the issue of applying a data operations, and not operated the monitoring requirements. Note that substitution procedure to represent intermittently, seasonally, or on some a source’s units must continue to meet actual emissions or pollution control other non-fulltime basis. their 30-boiler operating day emissions performance, we are not requiring data Comment: HCl CEMS. In general, limits during malfunction periods. substitutions under this rule. We commenters argued that HCl CEMS do Comment: 40 CFR part 75 Issues. believe, however, that defensibility not have an approved performance There were a number of general concerns make it incumbent on the specification and are not widely comments about the value of relying on source to collect and evaluate other demonstrated as a proven technology. 40 CFR part 75 requirements, including information in accordance with 40 CFR Those concerns were also mentioned for elements such as conditional data section 63.6(f)(3) during periods of HF CEMS. validation. The commenters generally monitoring downtime to assure Response: We disagree with agreed that the 40 CFR part 75 bias test compliance with the applicable commenters’ contention that continuous and bias adjustment factor, and the 40 emissions limitations and standards. HCl monitoring is premature or not CFR part 75 substitute data provisions We believe that enforcement available for the measurement at the should not apply. Instead of substitute authorities also can and should emission limits set in the final rule. HCl data, many commenters suggested that determine whether a source is meeting CEMS are being used on source we needed to clarify the valid reasons any monitoring system operating

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requirements. Should the source or the pollutants (PM, HAP metals, etc.) have also disagree that the system to receive enforcement authority be concerned different data demands. We recognize the compliance data must be operational about the representativeness of data that minor revisions of the ECMPS will prior to establishing the requirement for such as during periods of missing data, fulfill our data needs for most regulated sources to submit compliance either one may consider collecting continuously measured pollutants and data electronically. We are on track to information through other means (e.g., we will make these modifications for have the capability to receive electronic supplemental emissions testing) to fill receipt of the additional CEMS data. We compliance tests through our CDX in data gaps not only because such gaps also recognize the need for substantial sufficient time to receive all utility are deviations from the rule but such modifications to the ECMPS to source test reports required by this final gaps can lead to uncertainty about accommodate the data needs for rule. compliance status. periodically measured pollutants and We do plan a separate and We further believe that the final rule certain CEMS data such as PM CEMS independent regulatory action to provides sufficient means to ensure data and possibly HAP metals CEMS implement electronic reporting for CMS performance and ongoing data. Although major modifications of regulated entities which are covered by compliance without specifying an the ECMPS would be required for past and future rules. Although we have arbitrary numerical minimum data periodic compliance tests by isokinetic provided draft procedures for the availability or data substitution and instrumental test methods (as well development of emissions factors, that requirement. We believe that specifying as certain types of CEMS), only minor effort is an ancillary effort to the failure to collect required or otherwise revisions are required of the ERT to electronic delivery of compliance test excepted data as a deviation from the receive these tests. We are reports. It is our intention to convert to rule will provide the necessary implementing the changes in the ERT the electronic delivery and storage of all incentive to collect data sufficient to that are required to provide the software air emissions compliance source test demonstrate compliance with the limits tools to implement the delivery of these data. With this transition, we believe in the final rule. performance test data to us. this valuable information will be more Comment: Recordkeeping. Several The electronic submission of readily available not only for commenters opposed the requirements compliance test reports to us through compliance purposes but also for a related to maintaining records on site the Central Data Exchange (CDX) is not variety of other uses. and for 5 years. solely for the purpose of developing I. Emissions Averaging Response: We believe the improved emissions factors as some recordkeeping and retention commenters assert. Although populating Comment: In response to our request requirements are consistent with other WebFIRE will allow us to improve for comments on the suitability of requirements already in place, emissions factors, we intend to use data emissions averaging and need for a specifically 40 CFR 63.10 (b). stored in WebFIRE as the primary discount factor, we received a range of In addition, the 5-year retention location for compliance test reports for suggestions, including requests for period is the general rule for all use by regulatory authorities. The clarification regarding eligibility, points recordkeeping for all sources under the electronic submission of compliance for and against the need for a discount part 70 operating permits program. test reports is a continuation of our factor, and suggestions to ease Given that the General Provisions for 40 efforts to bring the submission and implementation. CFR part 63 and part 70 already sharing of environmental data into the Response: We are finalizing that establish a 5-year retention period, we modern age. The storage of this owners and operators of existing believe it is justified in using those compliance data in our WebFIRE affected sources may demonstrate precedents for the retention periods provides a convenient location which is compliance by emissions averaging for under this subpart. If we stayed silent already used to store source test data. EGUs at the affected source that are on retention period in this subpart, the As federal and state and local within a single subcategory and that rely General Provisions would provide for agencies’ data systems mature, on emissions testing as the compliance the 5-year retention as would the part 70 information provided through the ERT demonstration method. See section VI of requirements. Thus, this action does not will be used to populate these data thie preamble for a fuller discussion. establish any new retention systems. We are currently upgrading the J. LEE Criteria requirements, but merely confirms that AIRS Facility System and expect to the existing retention requirements replace manually entered information Comment: A commenter supported apply. with electronic population from the the LEE provisions but believed one of Comment: Electronic Reporting. In the ERT. We are also working with several the LEE eligibility criteria should set at proposed rule, we requested comment state and local agencies to adopt the use 29.0 lb/year, rather than 22.0 lb/year. on using ECMPS for reporting under of the ERT for delivery of compliance The commenter suggested 29.0 lb/year this rule, as well as other options test reports. The ERT is also much to be an equally reasonable cut point, including the ERT. Commenters improved since the version used during especially since that value matches the generally supported the use of ECMPS, the 2010 ICR process, and there is no low mass emitter Hg monitoring cutoff especially for CEMS data. Some expectation that the information to be in CAMR and the low mass emitter Hg commenters requested an additional reported under this final rule will be as monitoring cutoff that several states rulemaking on the specific data extensive as some of the data reported have adopted, including Illinois, 35 Ill. elements to be collected. There were for the 2010 ICR purposes. Admin. Code section 225.240(a)(4). some concerns raised about the ERT We disagree that a separate and (See, e.g., Colorado (5 Colo. Code Regs. given experience during the 2010 ICR independent regulatory action is section 1 00 1–8, Reg. No.6, part B, process during the development of this required to implement electronic Section VIII.B.l0); Michigan (Mich. rule. reporting for selected regulated sources. Admin. Code R. 336.2160); Montana Response: We recognize that Each of these regulatory actions for (Mont. Admin. R. 17.8771(12))). Further, emissions reporting for continuously selected source categories provides a LEE cutoff of 29.0 lb would eliminate measured pollutants (SO2, NOX, etc.) ample notice and the opportunity for conflicts and confusion with low mass and for periodically measured individuals to provide comment. We emitter provisions in existing state Hg

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programs and significantly reduce NSPS for EGUs (40 CFR part 60, subpart clarifications and corrections to existing compliance costs and burdens for the Da), industrial-commercial-institutional provisions of the subparts. additional qualifying units without steam generating units (40 CFR part 60, A. What are the requirements for new adversely affecting compliance subpart Db), and small industrial- EGUs (40 CFR part 60, subpart Da)? assurance with the EGU NESHAP Hg commercial-institutional steam emission limits or materially increasing generating units (40 CFR part 60, The filterable PM emissions standard the number of potential qualifying LEEs. subpart Dc). for new and reconstructed EGUs is 11 Given the many other costly burdens The NSPS for EGUs (40 CFR part 60, nanograms per joule (ng/J) (0.090 pound that the rule would impose, the benefit subpart Da) were originally promulgated per megawatt hour (lb/MWh)) gross of LEE to a qualifying unit is not on June 11, 1979 (44 FR 33580) and energy output regardless of the type of insignificant. apply to units capable of firing more fuel burned. The PM emissions standard Response: The Agency reviewed the than 73 megawatts (MW) (250 for modified EGUs is essentially commenter’s suggestions, and one of the MMBtu/h) heat input of fossil fuel that equivalent to the existing requirements LEE eligibility criteria in the rule has commenced construction, of 13 ng/J (0.015 lb/MWh) heat input been revised from 22.0 to 29.0 lb of Hg reconstruction, or modification after regardless of the type of fuel burned. per year. The Agency finds the result of September 18, 1978. The NSPS for EGUs Compliance with this emission limit can consistency with existing state also apply to industrial-commercial- be determined using testing, monitoring, regulations outweighs the two percent institutional cogeneration units that sell and other compliance provisions similar difference in nationwide Hg mass more than 25 MW and more than one- to those for PM standards set forth in emissions, from 5 percent to 7 percent, third of their potential output capacity the existing rule. While not required, for LEE eligibility. to any utility power distribution system. PM CEMS may be used as an alternative The most recent significant amendments method to demonstrate continuous VIII. Background Information on the to emission standards under 40 CFR compliance and as an alternative to NSPS part 60, subpart Da, were promulgated opacity and parameter monitoring A. What is the statutory authority for in 2006 (71 FR 9866) resulting in new requirements. The SO emission limit for new and this final NSPS? PM, SO2, and NOP2 limitations for 40 2 CFR part 60, subpart Da units. reconstructed EGUs is 130 ng/J (1.0 lb/ New source performance standards The NSPS for industrial-commercial- MWh) gross energy output or 97 percent implement CAA section 111(b), and are institutional steam generating units (40 reduction regardless of the type of fuel issued for categories of sources which CFR part 60, subpart Db) apply to units burned with one exception. The EPA cause, or contribute significantly to, air for which construction, modification, or neither proposed to amended the SO2 pollution which may reasonably be reconstruction commenced after June standard for coal refuse-fired EGUs, not anticipated to endanger public health or 19, 1984, that have a heat input capacity reopened the issue of whether coal welfare. Section 111 of the CAA greater than 29 MW (100 MMBtu/h). refuse-fired EGUs is an appropriate requires that NSPS reflect the Those standards were originally subcategory, and, therefore, that application of the best system of promulgated on November 25, 1986 (51 emissions standard is unchanged. The emissions reductions which (taking into FR 42768) and also have been amended SO2 emission limit for modified EGUs consideration the cost of achieving such since the original promulgation to burning any fuel is 180 ng/J (1.4 lb/ emissions reductions, any non-air reflect changes in BSER for these MWh) gross energy output or 90 percent quality health and environmental sources. reduction. Compliance with the SO2 impact and energy requirements) the The NSPS for small industrial- emission limit is determined on a 30- Administrator determines has been commercial-institutional steam boiler operating day rolling average adequately demonstrated. The level of generating units (40 CFR part 60, basis using a CEMS to measure SO2 control prescribed by CAA section 111 subpart Dc) were originally promulgated emissions and following the compliance historically has been referred to as ‘‘Best on September 12, 1990 (55 FR 37674) provisions in the proposed rule. Demonstrated Technology’’ or BDT. In and apply to units with a maximum The NOX emission limit for new and order to better reflect that CAA section heat input capacity greater than or equal reconstructed EGUs is 88 ng/J (0.70 lb/ 111 was amended in 1990 to clarify that to 2.9 MW (10 MMBtu/h) but less than MWh) gross energy output regardless of ‘‘best systems’’ may or may not be 29 MW (100 MMBtu/h). Those the type of fuel burned with one ‘‘technology,’’ the EPA is now using the standards apply to units that exception. The exception is that for new term ‘‘best system of emission commenced construction, and reconstructed EGUs that burn over reduction’’ or BSER. As was done reconstruction, or modification after 75 percent coal refuse (by heat input), previously in analyzing BDT, the EPA June 9, 1989. the NOX emission limit is 110 ng/J (0.85 uses available information and lb/MWh) gross energy output. The NOX considers the emission reductions and IX. Summary of the Final NSPS limit for modified EGUs is 140 ng/J (1.1 incremental costs for different systems The final rule amends the emission lb/MWh) gross energy output regardless available at reasonable cost. Then, the standards for SO2, NOP2, and PM in 40 of the type of fuel burned in the unit. EPA determines the appropriate CFR part 60, subpart Da. Only those Compliance with this emission limit is emission limits representative of BSER. units that begin construction, determined on a 30-boiler operating day Section 111(b)(1)(B) of the CAA requires modification, or reconstruction after rolling average basis using testing, EPA to periodically review and revise May 3, 2011, will be affected by the monitoring, and other compliance the standards of performance, as final rule. Compliance with the provisions similar to those in the necessary, to reflect improvements in emission limits of the final rule will be proposed rule. methods for reducing emissions. determined using testing, monitoring, As an alternative to the NOX standard, and other compliance provisions similar owners/operators of new and B. What is the regulatory authority for to those set forth in the existing reconstructed EGUs may elect to comply the final rule? standards. In addition to the emissions with a combined NOX/CO standard of The current standards for steam limits contained in the final rule, we 140 ng/J (1.1 lb/MWh) with one generating units are contained in the also are including several technical exception. The exception is that for new

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and reconstructed EGUs that burn over This too is addressed more fully in the damage the developing nervous system, 75 percent coal refuse (by heat input) on NSPS Final Rule RTC. which can impair children’s ability to an annual basis, the NOX/CO emission The proposal included alternate think and learn, and fine particles can limit is 160 ng/J (1.3 lb/MWh) gross emission standards for commercial cause adverse cardiovascular effects. energy output. Finally, owners/ demonstration projects. Proposed Further, reducing Hg deposition to operators of modified EGUs may elect to commercial demonstrations included ecosystems will benefit wildlife comply with a combined NOX/CO pressurized fluidized beds, multi- including fish, birds, and mammals. standard of 190 ng/J (1.5 lb/MWh). pollutant control technologies, and Fish and fish-eating birds, such as the advanced combustion controls. The common loon, and mammals suffer B. Additional Amendments final rule includes the commercial reproductive, survival, and behavioral See the Response to Comments demonstration permit exemption for impairments due to mercury exposure. document. pressurized fluidized beds and multi- These effects have also been observed in pollutant control technologies, but not X. Summary of Significant Changes insect-eating and wading birds, advanced combustion controls. Since Proposal including egrets and white ibis. Advanced combustion controls are Reductions of emissions targeted by this A. Emission Limits applicable to existing facilities and the rule also will slow acidification and The proposal included a combined exemption is not necessary to further eutrophication of water bodies. (filterable plus condensable) PM the development of the technology. Additionally, the EPA anticipates standard. The final standard is based B. Requirements During Startup, significant non-health, non-ecological only on filterable PM. No standard is Shutdown, and Malfunction benefits from this rule. The fine particle and SO emission reductions achieved being established for condensable PM. For startup and shutdown, the 2 by this rule will improve visibility, The rationale for this is set forth in the requirements for PM have changed since which is especially important for our Response to Comments (RTC) document proposal. For periods of startup and national parks. Emissions reductions for this final rule (the NSPS Final Rule shutdown, the EPA is finalizing work from this rule will also avoid an RTC). practice standards for PM in lieu of estimated $360 million (in $2007) of The proposal requested comment on numeric emission limits. Emissions climate-related costs, such as whether the final standard should incurred during periods of startup and agricultural productivity and property include a stand-alone NOX standard or shutdown for PM are not used in damage from increased flood risks. a combined NOX/CO standard. In demonstrations of compliance with the response to comments we received and 30-boiler operating day rolling average A. What are the air impacts? our own further evaluation of the period applicable for numeric emission situation, the final standard includes a standards. The EPA anticipates significant stand-alone NOX standard and an emission reductions under the final rule optional, but not required, combined XI. Public Comments and Responses to from coal-fired EGUs, which are of NOX/CO standard as an alternative to the Proposed NSPS particular interest due to their share of the amended NOX standard. Again, our See the Response to Comments total power sector emissions. In 2015, full rationale for this is set forth in the document. annual HCl emissions are projected to NSPS Final Rule RTC. The proposal also be reduced by 88 percent, Hg emissions XII. Impacts of the Final Rule included a request for comment on reduced by 75 percent, and PM2.5 whether the standard should be based The EPA anticipates significant public emissions reduced by 19 percent from on gross or net output. In response to health and environmental benefits from coal-fired EGUs greater than 25 MW. In comments we received and our own the rule as a direct result of the addition, the EPA projects SO2 emission further evaluation of the situation, the substantial reduction in the emissions of reductions of 41 percent, and annual final standards are based on an several pollutants, including SO2, Hg, CO2 reductions of 1 percent from coal- amended definition of gross output with acid gases and fine particles and metals. fired EGUs greater than 25 MW by 2015, an optional net output-based standard. For example, exposure to Hg can relative to the base case. See Table 7.

TABLE 7—SUMMARY OF EMISSION REDUCTIONS FROM COAL-FIRED EGUS GREATER THAN 25 MW (TPY)

CO2 SO2 NOX Mercury HCl PM2.5 (million metric (million tons) (million tons) (tons) (thousand tons) (thousand tons) tonnes)

Base Case ...... 3.3 1.7 27 45 270 1,906 MATS ...... 1.9 1.7 7 6 218 1,882 Change ...... ¥1.4 0.0 ¥20 ¥40 ¥52 ¥23 Note: Numbers may not add due to rounding.

The reductions in this table do not in additional HAP reductions from oil- capacity in 2015) may be uneconomic to account for reductions in other HAP fired EGUs, which are covered by the maintain and may be removed from which will occur as a result of this rule. rule but are not included in the EPA’s operation by 2015. These units are For instance, the fine particulate analysis of emission reductions. predominantly smaller, less frequently reductions presented above only partly B. What are the energy impacts? used, and are dispersed throughout the reflect reductions in many heavy metal country. If current forecasts of either particulates, and the HCl reductions The EPA projects that approximately natural gas prices or electricity demand 4.7 GW of coal-fired generation (less above only partly reflect reductions of were revised in the future to be higher, than 2 percent of all coal-fired capacity all acid gases. This rule will also result that would create a greater incentive to and 0.5 percent of total generation

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make further investments in these pollutants throughout the contiguous the environmental industry, primarily facilities and keep these units U.S. for the entire power system. driven by the high demand for new operational. Documentation for IPM can be found pollution control equipment. Overall, The final rule has other important in the docket for this rulemaking or at the results suggest that the final rule energy market implications. Average http://www.epa.gov/airmarkets/ could support a net of roughly 46,000 nationwide retail electricity prices are progsregs/epa-ipm/index.html. job years 355 in direct employment projected to increase in the contiguous The EPA performed a screening impacts in 2015. U.S. by 3.1 percent in 2015. The average analysis for impacts on small entities by There are other employment effects delivered coal price is projected to comparing compliance costs to sales/ that cannot be estimated quantitatively increase by less than 2 percent in 2015 revenues (e.g., sales and revenue tests). at this time. The employment gains as a result of shifts within and across The EPA’s analysis can be found in related to the new pollution controls are coal types. The EPA also projects that Chapter 7 of the RIA for this rule. The likely to be tempered by some losses electric power sector-delivered natural EPA has also prepared a Final due to certain coal retirements. On the gas prices will increase by between 0.3 Regulatory Flexibility Analysis (FRFA) other hand, some of those workers who and 0.6 percent over the 2015 to 2030 that discusses alternative regulatory or lose their jobs due to plant retirements timeframe, on average, and that natural policy options that minimize the rule’s could find alternative employment gas use for electricity generation will small entity impacts. operating the replacement electricity Although a stand-alone analysis of increase by less than 200 billion cubic generating equipment or new pollution employment impacts is not included in feet (BCF) in 2015. These impacts are controls at nearby units. Finally, job a standard cost-benefit analysis, the well within the range of price variability losses due to reduced coal demand may current economic climate has led to that is regularly experienced in natural be offset by job gains due to increased heightened concerns about potential job gas markets. Finally, the EPA projects natural gas demand, potentially impacts. Executive Order 13563 coal production for use by the power resulting in a positive net change in specifically states that our ‘‘regulatory sector, a large component of total coal employment due to fuel demand system must protect public health, production, will decrease by 10 million changes. welfare, safety, and our environment tons in 2015 from base case levels, The basic approach to estimate these while promoting economic growth, employment impacts involved using which is about 1 percent of total coal innovation, competitiveness, and job produced for the electric power sector IPM projections from the final rule creation’’ (emphasis added). analysis, in particular the amount of in that year. Under conditions of full employment, existing coal-fired capacity that is it is conventional to assume that C. What are the cost impacts? projected to be retrofit with pollution regulations will merely shift jobs from control technologies. These data, along The power industry’s ‘‘compliance one sector to another, without having a with data on labor and resource needs costs’’ are represented in this analysis as material effect on employment levels. of new pollution controls and labor the change in electric power generation Potential employment effects are of productivity from engineering studies costs between the base case and policy greater concern in the current economic and secondary sources, are used to case in which the sector pursues climate, with high levels of estimate employment impacts for the pollution control approaches to meet employment, because of the risk that pollution control industry in 2015. For the MATS emission standards. In displaced workers may not find more information, please refer to simple terms, these costs are the alternative jobs. In addition, regulations Chapter 6 and appendix 6B in the RIA. resource costs of direct power industry that result in firms hiring workers, in The EPA relied on Morgenstern, et al., expenditures to comply with the EPA’s order to ensure compliance, may have a (2002), to identify three economic requirements. positive effect on employment. The EPA projects that the annual During sustained periods of excess mechanisms by which pollution incremental compliance cost of MATS unemployment, the opportunity cost of abatement activities can influence jobs is $9.6 billion in 2015 ($2007). The labor required by regulated sectors to in the regulated sector separately from annualized incremental cost is the bring their facilities into compliance the short-term employment effects: D Higher production costs raise market projected additional cost of complying with an environmental regulation may prices, higher prices reduce with the rule in the year analyzed, and be lower than it would be during a consumption, and employment within includes the amortized cost of capital period of full employment (particularly an industry falls (‘‘demand effect’’); investment and the ongoing costs of if regulated industries employ otherwise D Pollution abatement activities operating additional pollution controls, idled labor to design, fabricate, or install require additional labor services to needed new capacity, shifts between or the pollution control equipment produce the same level of output (‘‘cost amongst various fuels, and other actions required under this final rule). associated with compliance. effect’’); and Consistent with EO 13563, the EPA D Post-regulation production The total incremental compliance cost includes estimates of job impacts technologies may be more or less labor includes compliance costs modeled in associated with the final rule. In the intensive (i.e., more/less labor is IPM of $9.4 billion, costs modeled electricity sector, the EPA estimates that required per dollar of output) (‘‘factor- outside of IPM for oil-fired EGUs of $56 the net employment effect will range ¥ shift effect’’). million, and monitoring, reporting, and from 15,000 to +30,000 jobs, with a Using plant-level Census information recordkeeping costs of $158 million. central estimate of +8,000. The EPA also between the years 1979 and 1991, D. What are the economic impacts? presents an estimate of short-term employment effects as a result of 355 Numbers of job years are not the same as For this final rule, EPA analyzed the increased demand for pollution control numbers of individual jobs, but represents the costs using the IPM. The IPM is a equipment. amount of work that can be performed by the dynamic linear programming model that The results of this analysis, found in equivalent of one full-time individual for a year (or Chapter 6 of the RIA, indicate that the FTE). For example, 25 job years may be equivalent can be used to examine the economic to five full-time workers for five years, 25 full-time impacts of air pollution control policies final rule has the potential to provide workers for one year, or one full-time worker for 25 for a variety of HAP and other increases in short-term employment in years.

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Morgenstern,et al., estimate the size of increases in pollution abatement please refer to Chapter 6 of the RIA for each effect for four polluting and expenditures may increase employment this final rule.357 regulated industries (petroleum, plastic in the relevant sectors and do not In the directly affected sector, the EPA material, pulp and paper, and steel). On necessarily cause economically estimates that the net employment effect average across the four industries, each significant employment changes. The will range from ¥15,000 to +30,000 additional $1 million spent on pollution conclusion is similar to that of Berman jobs, with a central estimate of +8,000. abatement results in a small net increase and Bui (2001) who found that The ranges of job effects for the of 1.55 jobs; the estimated effect is not increased air quality regulation in Los electricity sector, as calculated using the a statistically different from zero. As a Angeles did not cause large employment Morgenstern,et al., approach are listed result, the authors conclude that changes.356 For more information, in Table 8.

TABLE 8—RANGE OF JOB EFFECTS FOR THE ELECTRICITY SECTOR

Estimates using Morgenstern, et al., (2001) Factor shift Net Demand effect Cost effect effect effect

Change in Full-Time Jobs per Million Dol- ¥3.56 ...... 2.42 ...... 2.68 ...... 1.55. lars of Environmental Expenditure a. Standard Error ...... 2.03 ...... 0.83 ...... 1.35 ...... 2.24. EPA estimate for Final Rule b ...... ¥39,000 to ...... +4,000 to ...... +200 to ...... ¥15,000 to +2,000 ...... +21,000 ...... +27,000 ...... +30,000. a Expressed in 1987 dollars. See footnote a from Table 6–2 of the RIA for inflation adjustment factor used in the analysis. b According to the 2007 Economic Census, the electric power generation, transmission and distribution sector (NAICS 2211) had approximately 510,000 paid employees.

The EPA recognizes there may be effects as well as effects on brain MeHg exposures, as there is no other job effects that are not considered development and memory functions and consensus among scientists on the dose- in the Morgenstern,et al., study. support the conclusions based on response functions for these effects. In Although EPA has considered some epidemiology studies. The NAS noted addition, there is inconsistency among economy-wide changes, we do not have that their recommended available studies as to the association sufficient information to quantify other neurodevelopmental endpoints for an between MeHg exposure and various job effects associated with this rule. RfD are associated with the ability of cardiovascular system effects. The children to learn and to succeed in pharmacokinetics of some of the E. What are the benefits of this final school. They concluded the following: exposure measures (such as toenail Hg rule? ‘‘The population at highest risk is the levels) are not well understood. The 1. Benefits of Reducing HAP Emissions children of women who consumed large studies have not yet received the review amounts of fish and seafood during and scrutiny of the more well- a. Human Health and Environmental pregnancy. The committee concludes established neurotoxicity data base. Effects Due to Exposure to MeHg. In this that the risk to that population is likely d. Genotoxic Effects of Exposure to section, we provide a qualitative to be sufficient to result in an increase MeHg. The Mercury Study noted that description of human health and in the number of children who have to MeHg is not a potent mutagen but is environmental effects due to exposure struggle to keep up in school.’’ capable of causing chromosomal to MeHg. The NAS Study (NRC, 2000) c. Cardiovascular Impacts of Exposure damage in a number of experimental provides a thorough review of the to MeHg. The NAS summarized data on systems. The NAS Study indicated that effects of MeHg on human health. Many cardiovascular effects available up to evidence that human exposure to MeHg of the peer-reviewed articles cited in 2000. Based on these and other studies, causes genetic damage is inconclusive; this section are publications originally the NAS Study concluded that they note that some earlier studies cited in the NAS Study. In addition, the ‘‘Although the data base is not as showing chromosomal damage in EPA has conducted literature searches extensive for cardiovascular effects as it lymphocytes may not have controlled to obtain other related and more recent is for other end points (i.e., neurologic sufficiently for potential confounders. publications to complement the material effects) the cardiovascular system One study of adults living in the summarized by the NAS in 2000. appears to be a target for MeHg toxicity Tapajo´s River region in Brazil b. Neurologic Effects of Exposure to in humans and animals.’’ The report (Amorimet al., 2000) reported a direct MeHg. In its review of the literature, the also stated that ‘‘additional studies are relationship between MeHg NAS found neurodevelopmental effects needed to better characterize the effect concentration in hair and DNA damage to be the most sensitive and best of MeHg exposure on blood pressure in lymphocytes, as well as effects on documented endpoints and concluded and cardiovascular function at various chromosomes. Long-term MeHg that they are appropriate for establishing stages of life.’’ exposures in this population were an RfD (NRC, 2000); in particular NAS Additional cardiovascular studies believed to occur through consumption supported the use of results from have been published since 2000. The of fish, suggesting that genotoxic effects neurobehavioral or neuropsychological EPA did not develop a quantitative (largely chromosomal aberrations) may tests. The NAS Study (NRC, 2000) noted dose-response assessment for result from dietary, chronic MeHg that studies in animals reported sensory cardiovascular effects associated with exposures similar to and above those

356 For alternative views in economic journals, 357 It should be noted that if more labor must be aggregate supply curve to shift to the left, and see Henderson (1996) and Greenstone (2002). used to produce a given amount of output, then this businesses will produce less, all other things being implies a decrease in labor productivity. A decrease equal. in labor productivity will cause a short-run

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seen in the populations studied in the reproductive deficits would have an exhibit liver and possibly kidney effects. Faroe Islands and Republic of effect on populations. Although ibises and egrets are most Seychelles. Mercury also affects avian species. In abundant in coastal areas and these e. Immunotoxic Effects to Exposure to previous reports 359 much of the focus studies were conducted in south Florida MeHg. Although exposure to some has been on large piscivorous species, in and Nevada, the ranges of ibises and forms of Hg can result in a decrease in particular the common loon. According egrets extend to a large portion of the immune activity or an autoimmune to Evers,et al., significant adverse effects U.S. response (ATSDR, 1999), evidence for from Hg on breeding loons have been Insectivorous birds have also been immunotoxic effects of MeHg is limited found to occur, including behavioral shown to suffer adverse effects due to (NRC, 2000). (reduced nest-sitting), physiological Hg exposure. Songbirds such as f. Other Hg-Related Human Toxicity (flight feather asymmetry) and Bicknell’s thrush, tree swallows, and the Data. Based on limited human and reproductive (chicks fledged/territorial great tit have shown reduced animal data, MeHg is classified as a pair) effects and reduced survival.360 reproduction, survival, and changes in ‘‘possible’’ human carcinogen by the Additionally, Evers, et al., (see footnote singing behavior. Exposed tree swallows 365 International Agency for Research on 5), believe that the weight of evidence produced fewer fledglings, had lower 366 Cancer (IARC, 1994) and in IRIS indicates that population-level effects survival rates, and had compromised 367 (USEPA, 2002). The existing evidence occur in parts of Maine and New immune competence. The great tit supporting the possibility of Hampshire, and potentially in broad has exhibited reduced singing behavior carcinogenic effects in humans from areas of the loon’s range. and smaller song repertoire in areas of high contamination.368 low-dose chronic exposures is tenuous. Recently, attention has turned to other In mammals, adverse effects have Multiple human epidemiological piscivorous species such as the white studies have found no significant been observed in mink and river otter, ibis and great snowy egret. These both fish eating species. For otter from association between Hg exposure and wading birds have a very wide diet overall cancer incidence, although a few Maine and Vermont, maximum including crayfish, crabs, snails, insects concentrations of Hg in fur nearly equal studies have shown an association and frogs. White ibis have been between Hg exposure and specific types or exceed a level associated with observed to have decreased foraging mortality and concentration in liver for of cancer incidence (e.g., acute leukemia efficiency361 and have been shown to and liver cancer) (NAS, 2000). mink in Massachusetts/Connecticut and exhibit decreased reproductive success the levels in fur from mink in Maine Some evidence of reproductive and and altered pair behavior.362 In egrets, renal toxicity in humans from MeHg exceed concentrations associated with Hg has been implicated in the decline acute mortality.369 Adverse sublethal exposure exists. However, overall, 363 of the species in south Florida, and effects may be associated with lower Hg human data regarding reproductive, Hoffman364 has shown that egrets renal, and hematological toxicity from concentrations and consequently may be more widespread than potential MeHg are very limited and are based on 359 U.S. Environmental Protection Agency (EPA). acute effects. These effects may include studies of the two high-dose poisoning 1997. Mercury Study Report to Congress. Volume episodes in Iraq and Japan or animal V: Health Effects of Mercury and Mercury increased activity, poorer maze Compounds. EPA–452/R–97–007. U.S. EPA Office performance, abnormal startle reflex, data, rather than epidemiological of Air Quality Planning and Standards, and Office studies of chronic exposures at the and impaired escape and avoidance of Research and Development; U.S. Environmental behavior.370 levels of interest in this analysis. Protection Agency (U.S. EPA). 2005. Regulatory h. Methodology for Partial Hg Benefits g. Ecological Effects of Hg. Deposition Impact Analysis of the Final Clean Air Mercury Estimation. The EPA has conducted a of Hg to watersheds can also have an Rule. Research Triangle Park, NC., March; EPA report no. EPA–452/R–05–003. Available on the national-scale analysis of the benefits to impact on ecosystems and wildlife. Internet at http://www.epa.gov/ttn/ecas/regdata/ recreational anglers of avoided IQ loss Mercury contamination is present in all RIAs/mercury_ria_final.pdf. related to reductions of Hg emissions environmental media, with aquatic 360 Evers, DC, Savoy, LJ, DeSorbo, CR, Yates, DE, systems experiencing the greatest Hanson, W, Taylor, KM, Siegel, LS, Cooley, JH, Jr., Bank, MS, Major, A, Munney, K, Mower, BF, Vogel, Toxicology and Environmental Health, Part A. 72: exposures due to bioaccumulation. HS, Schoch, N, Pokras, M, Goodale, MW, Fair, J. 20, 1223–1241, 2009. Bioaccumulation refers to the net uptake Adverse effects from environmental mercury loads 365 Brasso, RL, and Cristol, DA. Effects of mercury of a contaminant from all possible on breeding common loons. Ecotoxicology. 17:69– exposure in the reproductive success of tree pathways and includes the 81, 2008; Mitro, MG, Evers, DC, Meyer, MW, and swallows (Tachycineta bicolor). Ecotoxicology. Piper, WH. Common loon survival rates and 17:133–141, 2008. accumulation that may occur by direct mercury in New England and Wisconsin. Journal of 366 Hallinger, KK, Cornell, KL, Brasso, RL, and exposure to contaminated media as well Wildlife Management. 72(3): 665–673, 2008. Cristol, DA. Mercury exposure and survival in free- as uptake from food. 361 Adams, EM, and Frederick, PC. Effects of living tree swallows (Tachycineta bicolor). A review of the literature on effects of methylmercury and spatial complexity on foraging Ecotoxicology. Doi: 10.1007/s10646–010–0554–4, Hg on fish 358 reports results for behavior and foraging efficiency in juvenile white 2010. ibises (Eudocimus albus). Environmental 367 Hawley, DM, Hallinger, KK, Cristol, DA. numerous species including trout, bass Toxicology and Chemistry. Vol 27, No. 8, 2008. Compromised immune competence in free-living (large and smallmouth), northern pike, 362 Frederick, P, and Jayasena, N. Altered pairing tree swallows exposed to mercury. Ecotoxicology. carp, walleye, salmon, and others from behavior and reproductive success in white ibises 18:499–503, 2009. laboratory and field studies. The effects exposed to environmentally relevant concentrations 368 Gorissen, L, Snoeijs, T, Van Duyse, E, and of methylmercury. Proceedings of The Royal Eens, M. Heavy metal pollution affects dawn of MeHg in fish are reproductive in Society B. doi: 10–1098, 2010. singing behavior in a small passerine bird. nature. Although we cannot determine 363 Sepulveda, MS, Frederick, PC, Spalding, MG, Oecologia. 145: 540–509, 2005. at this time whether these reproductive and Williams, GE, Jr. Mercury contamination in 369 Yates, DE, Mayack, DT, Munney, K, Evers DC, deficits are affecting fish populations free-ranging great egret nestlings (Ardea albus) from Major, A, Kaur, T, and Taylor, RJ. Mercury levels across the U.S. it should be noted that southern Florida, USA. Environmental Toxicology in mink (Mustela vison) and river otter (Lonra and Chemistry. Vol. 18, No. 5, 1999. canadensis) from northeastern North America. it would seem reasonable that over time 364 Hoffman, DJ, Henny, CJ, Hill, EF, Grover, RA, Ecotoxicology. 14, 263–274, 2005. Kaiser, JL, Stebbins, KR. Mercury and drought along 370 Scheuhammer, AM, Meyer MW, 358 Crump, KL, and Trudeau, VL. Mercury- the lower Carson River, Nevada: III. Effects on blood Sandheinrich, MB, and Murray, MW. Effects of induced reproductive impairment in fish. and organ biochemistry and histopathology of environmental methylmercury on the health of wild Environmental Toxicology and Chemistry. Vol. 28, snowy egrets and black-crowned night-herons on birds, mammals, and fish. Ambio. Vol.36, No.1, No. 5, 2009. Lahontan Reservoir, 2002–2006. Journal of 2007.

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and subsequent deposition that will be decrement in offspring, the following nationally.371 These losses represent achieved by this rule. Because the dose-response relationship was expected present value of declines in primary measurable health effect of developed based on the summary future net earnings over the entire concern—developmental neurological findings reported in Axelrad et al., lifetimes of the children who are abnormalities in children—occurs as a (2007). prenatally exposed during the year result of in-utero exposures to Hg, the The valuation approach used to assess 2005. With a 7 percent discount rate, the specific population of interest in this monetary losses due to IQ decrements is present-year value range is considerably case is prenatally exposed children. To based on an approach applied in lower: $22.8 million to $50.0 million. identify and estimate the size of this previous EPA analyses (EPA, 2008). The For this rule, the EPA generated exposed population, the benefits approach expresses the potential loss to estimates of aggregate nationwide analysis focused on pregnant women in an affected individual resulting from IQ benefits associated with reductions in freshwater recreational angler decrements in terms of foregone future Hg exposures and resulting reductions households. Estimating Hg exposures earnings (net of changes in education in IQ losses. Most importantly, the for this exposure pathway and costs) for that individual. benefits of the 2016 MATS scenario population of interest requires three The estimate for ‘‘Present Value of (relative to the 2016 base case) are main components: (1) The size of the Lifetime Earnings’’ is derived using estimated to range between $4 million exposed population of interest (annual earnings and labor force participation and $6 million (assuming a 3 percent number of pregnant women in rate data from the Bureau of Labor discount rate), because of an estimated freshwater angler households during the Statistics 2006 Current Population 511 point reduction in IQ losses. The year), (2) the average concentration of Survey. Estimates of the average effect EPA recognizes that these calculated MeHg in noncommercial freshwater fish of a 1-point increase in IQ on lifetime benefits are a small subset of the filets consumed, and (3) the average earnings range from a 1.76 percent benefits of reducing Hg emissions. increase (Schwartz, 1994) to a 2.379 daily consumption rate of 2. Health and Welfare Co-Benefits noncommercial freshwater fish. The Hg percent increase (Salkever, 1995). The concentrations of fish in the percentage increases in the two studies Emission controls installed to meet waterbodies where the fish are caught reflect both the direct impact of IQ on the requirements of this rule will are modeled using Mercury Maps to hourly wages and indirect effects on generate co-benefits by reducing criteria project the decline in concentrations annual earnings as the result of pollutants including PM2.5 and SO2, as due to the rule. To approximate the additional schooling and increased well as CO2. For this rule, we were only percentage of freshwater fishing trips labor force participation. The estimate able to estimate the mortality benefits of (and exposed individuals) from each for years of additional schooling is PM2.5 reductions due to changes in Census tract matched to each waterbody based on Schwartz (1994), who reports emissions of SO2 and direct PM2.5 and type, the EPA used state-level averages. an increase of 0.131 years of schooling climate benefits resulting from CO2 These averages were calculated for each per IQ point. reductions. Additional co-benefits may state, based on the portion of residents’ In addition to this positive net effect result from decreases in PM2.5 morbidity freshwater fishing trips that are to each on earnings, an increase in IQ is also impacts, decreases in sulfur deposition waterbody type, based on 2001 National assumed to have a positive effect on the and direct health effects of SO2, and Survey of Fishing, Hunting, and amount of time spent in school and on improvements in visibility in national Wildlife-Associated Recreation associated costs. To incorporate (1) parks and wilderness areas. Total co- (FHWAR) data. uncertainty regarding the size of the benefits may be higher than the partial Data from the 1994 National Survey percentage change in future earnings estimates of co-benefits provided here. on Recreation and the Environment and (2) different assumptions regarding Our best estimate of the monetized (NSRE) were used to approximate the the discount rate, the resulting value health and climate co-benefits of this percentage of freshwater fishing trips estimates for the average net loss per IQ rule in 2016 at a 3 percent discount rate (and exposed individuals) matched to point decrement are expressed as a are $37 billion to $90 billion or $33 different distances from anglers’ range. Assuming a 3 percent discount billion to $81 billion at a 7 percent residential location. rate, value IQ ranges from $8,013 (using discount rate (2007$). Using alternate To determine an appropriate daily the Schwartz estimates) to $11,859 relationships between PM2.5 and fish consumption rate for the analysis, (using the Salkever estimates) in premature mortality supplied by the EPA conducted an extensive review increased earnings per year per 1-point experts, higher and lower health co- of existing literature characterizing self- IQ increase. With a 7 percent discount benefits estimates are plausible, but caught freshwater fish consumption. rate assumption, the value IQ estimates most of the expert-based estimates fall Based on this review, it was decided range from $893 to $1,958 in increased between these two estimates.372 that the ingestion rates for recreational earnings per year per 1-point IQ a. Human Health Co-Benefits. To freshwater fishers, specified as increase. estimate the human health co-benefits of ‘‘recommended’’ in the EPA’s The EPA analyzed the aggregate this rule, the EPA used benefit-per-ton ‘‘Environmental Exposure Factors national IQ and present-value loss Handbook’’ (EPA, 1997), represented the estimates for two base case and three 371 Monetized benefits estimates are for an emission control scenarios. The highest immediate change in MeHg levels in fish. If a lag most appropriate values to use in this in the response of MeHg levels in fish were analysis. losses are estimated for the 2005 base assumed, the monetized benefits could be Estimating the IQ decrements in case. For the population of prenatally significantly lower, depending on the length of the children that result from mothers’ exposed children included in the lag and the discount rate used. As noted in the discussion of the Mercury Maps modeling, the prenatal ingestion of Hg from fish analysis (almost 240,000), Hg exposures relationship between deposition and fish tissue required two steps. First, based on the under baseline conditions during the MeHg is proportional in equilibrium, but the estimated average daily maternal year 2005 are estimated to have resulted Mercury Maps approach does not provide any ingestion rate, the expected Hg in more than 25,500 IQ points lost. information on the time lag of response. concentration in the hair of exposed Assuming a 3 percent discount rate, the 372 Roman, et al., 2008. Expert Judgment Assessment of the Mortality Impact of Changes in pregnant women was estimated. present-year value of these losses ranges Ambient Fine Particulate Matter in the U.S. Second, to estimate the expected IQ from $204.8 million to $292.5 million Environ. Sci. Technol., 42, 7, 2268–2274.

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factors to quantify the changes in PM2.5- for this rule the air quality modeling related health effects in 2016 resulting related health impacts and monetized used a better spatial representation of from this rule. Table 10 presents the benefits based on changes in SO2 and the emission changes from EGUs. Using estimated annual monetary value of the direct PM2.5 emissions. These benefit- a benefit-per-ton approach adds another reduced incidence of quantified health per-ton factors were based on an interim important source of uncertainty to the endpoints in 2016 resulting from this baseline and policy scenario for which benefits estimates. For more details on rule. the creation of the benefit-per-ton full-scale ambient air quality modeling The reduction in premature fatalities and air quality-based human health factors and their application to emission reductions under this rule, please refer each year accounts for between 93 and benefits assessments were performed. 97 percent of the estimated health co- This general approach and methodology to the RIA for this rule in the docket. Table 9 presents the estimates of benefits that were monetized. is laid out in Fann, et al., (2009),373 but reduced annual incidence of PM2.5-

a TABLE 9—ESTIMATED REDUCTIONS IN INCIDENCE OF PM2.5-RELATED HEALTH EFFECTS IN 2016

Health effect Number of reduced cases

Adult Premature Mortality

Pope et al., (2002) (age >30) ...... 4,200. (1,200 to 7,200). Laden et al., (2006) (age >25) ...... 11,000. (5,000 to 17,000). Infant Premature Mortality (<1 year) ...... 20. (¥22 to 61). Chronic Bronchitis ...... 2,800. (88 to 5,600). Non-fatal heart attacks (age >18) ...... 4,700. (1,200 to 8,300). Hospital admissions—respiratory (all ages) ...... 830. (330 to 1,300). Hospital admissions—cardiovascular (age >18) ...... 1,800. (1,200 to 2,200). Emergency room visits for asthma (age <18) ...... 3,100. (1,600 to 4,700). Acute bronchitis (age 8–12) ...... 6,300. (¥1,400 to 14,000). Lower respiratory symptoms (age 7–14) ...... 80,000. (31,000 to 130,000). Upper respiratory symptoms (asthmatics age 9–11) ...... 60,000. (11,000 to 110,000). Asthma exacerbation (asthmatics 6–18) ...... 130,000. (4,500 to 450,000). Lost work days (ages 18–65) ...... 540,000. (460,000 to 620,000). Minor restricted-activity days (ages 18–65) ...... 3,200,000. (2,600,000 to 3,800,000). a Values rounded to two significant figures. Co-benefits from reducing exposure to ozone, other criteria pollutants, and HAP, as well as reduc- ing visibility impairment and ecosystem effects are not included here.

a TABLE 10—ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-RELATED HEALTH BENEFITS IN 2016

Health effect Monetized benefits

Adult Premature Mortality

Pope, et al., (2002) (age >30): 3% discount rate ...... $34. ($2.6 to $100). 7% discount rate ...... $30. ($2.4 to $92). Laden, et al., (2006) (age >25): 3% discount rate ...... $87. ($7.5 to $250). 7% discount rate ...... $78. ($6.8 to $230). Infant Premature Mortality (<1 year) ...... $0.2. ($¥0.2 to $0.8). Chronic Bronchitis ...... $1.4. ($0.1 to $6.4). Non-fatal heart attacks (age >18):

373 Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. type in estimates of the human health benefits of reducing a ton of air pollution.’’ Air Qual Atmos ‘‘The influence of location, source, and emission Health (2009) 2:169–176.

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a TABLE 10—ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-RELATED HEALTH BENEFITS IN 2016 —Continued

Health effect Monetized benefits

3% discount rate ...... $0.5. ($0.1 to $1.3). 7% discount rate ...... $0.4. ($0.1 to $1.0). Hospital admissions—respiratory (all ages) ...... $0.01. ($0.01 to $0.02). Hospital admissions—cardiovascular (age >18) ...... $0.03. (<$0.01 to $0.05). Emergency room visits for asthma (age <18) ...... <$0.01. Acute bronchitis (age 8–12) ...... <$0.01. Lower respiratory symptoms (age 7–14) ...... <$0.01. Upper respiratory symptoms (asthmatics age 9–11) ...... <$0.01. Asthma exacerbation (asthmatics 6–18) ...... <$0.01. Lost work days (ages 18–65) ...... $0.1. ($0.1 to $0.1). Minor restricted-activity days (ages 18–65) ...... $0.2. ($0.1 to $0.3).

Monetized Health Co-Benefits

Pope, et al., (2002): 3% discount rate ...... $36. ($2.8–$110). 7% discount rate ...... $33. ($2.5–$100). Laden, et al., (2006): 3% discount rate ...... $89. ($7.7–$260). 7% discount rate ...... $80. ($6.9–$240). a Values rounded to two significant figures. Co-benefits from reducing exposure to ozone, other criteria pollutants, and HAP, as well as reduc- ing visibility impairment and ecosystem effects are not included here.

It is important to note that the is limited to some extent by data gaps, mortality concentration-response magnitude of the PM2.5 co-benefits is model capabilities (such as geographic relationship. largely driven by the concentration coverage), and uncertainties in the In the RIA accompanying this response function for premature underlying scientific and economic rulemaking, rather than segmenting out mortality. Experts have advised the EPA studies used to configure the benefit and impacts predicted to be associated with to consider a variety of assumptions, cost models. Gaps in the scientific levels above and below a ‘‘bright line’’ including estimates based both on literature often result in the inability to threshold, the EPA includes a ‘‘lowest empirical (epidemiological) studies and estimate quantitative changes in health measured level’’ (LML) analysis that judgments elicited from scientific and environmental effects, or to assign illustrates the increasing uncertainty experts, to characterize the uncertainty economic values even to those health that characterizes exposure attributed to in the relationship between PM2.5 and environmental outcomes that can be levels of PM2.5 below the LML of each concentrations and premature mortality. quantified. The uncertainties in the epidemiological study used to estimate We cite two key empirical studies, one underlying scientific and economics PM2.5-related premature death. Figures based on the American Cancer Society literature (that may result in provided in the RIA show the cohort study 374 and the other based on overestimation or underestimation of distribution of baseline exposure to 375 the extended Six Cities cohort study. the co-benefits) are discussed in detail PM2.5, as well as the lowest air quality The analyses upon which this rule is in the RIA. Despite these uncertainties, levels measured in each of the based were selected from the peer- we believe the benefit analysis for this epidemiology cohort studies. This reviewed scientific literature. We used rule provides a reasonable indication of information provides a context for up-to-date assessment tools, and we the expected health co-benefits of the considering the likely portion of PM- believe the results are highly useful in rulemaking in future years under a set related mortality benefits occurring assessing this rule. of reasonable assumptions. above or below the LML of each study; Every benefit analysis examining the When characterizing uncertainty in in general, our confidence in the size of potential effects of a change in the PM-mortality relationship, the EPA the estimated reduction in PM2.5-related environmental protection requirements has historically presented a sensitivity premature mortality diminishes as analysis applying alternate assumed baseline concentrations of PM2.5 are 374 Pope et al., 2002. ‘‘Lung Cancer, lowered. Cardiopulmonary Mortality, and Long-term thresholds in the PM concentration- Exposure to Fine Particulate Air Pollution.’’ Journal response relationship. In its synthesis of Based on the modeled interim of the American Medical Association. 287:1132– the current state of the PM science, the baseline which is approximately 1141. EPA’s 2009 Integrated Science equivalent to the final baseline (see 375 Ladenet al., 2006. ‘‘Reduction in Fine Particulate Air Pollution and Mortality.’’ American Assessment for Particulate Matter Appendix A of the RIA), 11 percent and Journal of Respiratory and Critical Care Medicine. concluded that a no-threshold log-linear 73 percent of the estimated avoided 173:667–672. model most adequately portrays the PM- mortality impacts occur at or above an

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annual mean PM2.5 level of 10 mg/m3 areas as well as residential areas where EPA and other executive branch (the LML of the Ladenet al., 2006 people live, work, and recreate could be entities, and that concluded in February study)or 7.5 mg/m3 (the LML of the substantial. Because full-scale air 2010. We first used these SCC estimates Pope,et al., 2002 study), respectively. quality modeling was not performed for in the benefits analysis for the final joint Although the LML analysis provides this rule, we are unable to quantify EPA/DOT Rulemaking to establish some insight into the level of these visibility co-benefits for this rule. Light-Duty Vehicle Greenhouse Gas uncertainty in the estimated PM However, the estimated value of Emission Standards and Corporate mortality benefits, the EPA does not visibility benefits calculated from the Average Fuel Economy Standards; see view the LML as a threshold and modeled interim baseline and policy the rule’s preamble for discussion about continues to quantify PM-related scenario was $1.1 billion (in 2007$). application of the SCC (75 FR 25324; mortality impacts using a full range of These visibility benefits are not May 7, 2010). The SCC Technical modeled air quality concentrations. A included in the total co-benefits Support Document (SCC TSD) provides large fraction of the PM2.5-related estimate of the final policy scenario a complete discussion of the methods benefits occur below the level of the used as a basis for this final rule. The used to develop these SCC estimates.376 National Ambient Air Quality Standard distribution of emission reductions did The interagency group selected four (NAAQS) for PM at 15 mg/m3, which 2.5 not change substantially in the visibility SCC values for use in regulatory was set in 2006. It is important to regions studied, therefore visibility analyses, which we have applied in this emphasize that NAAQS are not set at a benefits of the final policy scenario are analysis: $5.9, $24.3, $39, and $74.4 per level of zero risk. Instead, the NAAQS likely to be of a similar magnitude. metric ton of CO emissions in 2016, in reflect the level determined by the Ecosystem and other welfare effects 2 2007 dollars. The first three values are Administrator to be protective of public include reduced acidification and, in based on the average SCC from three health within an adequate margin of the case of NO , eutrophication of water X integrated assessment models, at safety, taking into consideration effects bodies; possible reduced nitrate discount rates of 5, 3, and 2.5 percent, on susceptible populations. While contamination of drinking water; ozone respectively. Social cost of carbon benefits occurring below the standard vegetation damage; a reduction in the values at several discount rates are may be less certain than those occurring role of sulfate in Hg methylation; and included because the literature shows above the standard, EPA considers them reduced acid and particulate deposition that the SCC is quite sensitive to to be legitimate components of the total that causes damages to cultural assumptions about the discount rate, benefits estimate. monuments, as well as soiling and other and because no consensus exists on the It is important to note that the materials damage. To illustrate the appropriate rate to use in an monetized benefits include many but important nature of benefit categories intergenerational context. The fourth not all health effects associated with the EPA is currently unable to monetize, value is the 95th percentile of the SCC PM2.5 exposure. Benefits are shown as a we discuss the potential public welfare from all three values at a 3 percent range from Pope, et al., (2002), to Laden, and environmental impacts related to discount rate. It is included to represent et al., (2006). These studies assume that reductions in emissions required by this higher-than-expected impacts from all fine particles, regardless of their rule in the RIA, including reduced temperature change further out in the chemical composition, are equally visibility impairment, reduced effects extremes of the SCC distribution. Low potent in causing premature mortality from acid deposition, reduced effects probability, high impact events are because there is no clear scientific from nutrient enrichment, and reduced incorporated into all of the SCC values evidence that would support the vegetation effects from ambient through explicit consideration of their development of differential effects exposure to SO2 and NO2. estimates by particle type. Even though c. Climate co-benefits. This rule is effects in two of the three values as well as the use of a probability density we assume that all fine particles have expected to reduce CO2 emissions from equivalent health effects, the benefit- the electricity sector. The EPA has function for equilibrium climate per-ton estimates vary between directly- assigned a dollar value to reductions in sensitivity. Treating climate sensitivity emitted particles (carbonaceous and CO emissions using recent estimates of probabilistically results in more high 2 temperature outcomes, which in turn crustal particles) and SO2 emissions that the ‘‘social cost of carbon’’ (SCC). The form sulfate particles, based on the SCC is an estimate of the monetized leads to higher projections of damages. location of emission changes and damages associated with an incremental Applying the global SCC estimates magnitude of population exposure increase in carbon emissions in a given using a 3 percent discount rate, we changes. Regardless, however, the year or the per metric ton benefit estimate the value of the climate related assumption that all fine particles are estimate relating to decreases in CO2 benefits of this rule in 2016 is $360 equally potent in causing premature emissions. It is intended to include (but million (2007$), as shown in Table 11. mortality adds uncertainty to the is not limited to) changes in net See the RIA for more detail on the benefits estimate. agricultural productivity, human health, methodology used to calculate these b. Non-Climate Welfare Co-Benefits. property damage from increased flood benefits and additional estimates of Emission controls installed to comply risk, and the value of ecosystem services climate benefits using different discount with the requirements specified in this due to climate change. rates and the 95th percentile of the 3 rule will also generate co-benefits by The SCC estimates used in this percent discount rate SCC. Important improving visibility. We anticipate that analysis were developed through an limitations and uncertainties of the SCC improvements in visibility in Class I interagency process that included the approach are also described in the RIA.

376 Docket ID EPA–HQ–OAR–2009–0472–114577, Transportation, Environmental Protection Agency, Technical Support Document: Social Cost of Carbon National Economic Council, Office of Energy and for Regulatory Impact Analysis Under Executive Climate Change, Office of Management and Budget, Order 12866, Interagency Working Group on Social Office of Science and Technology Policy, and Cost of Carbon, with participation by Council of Department of Treasury (February 2010). Also Economic Advisers, Council on Environmental available at http://epa.gov/otaq/climate/ Quality, Department of Agriculture, Department of regulations.htm. Commerce, Department of Energy, Department of

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TABLE 11—ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-RELATED HEALTH BENEFITS AND CLIMATE BENEFITS IN 2016a

Effect Monetized benefits

Monetized Health Co-Benefits

Pope, et al., (2002): 3% discount rate ...... $36 ($2.8–$110) 7% discount rate ...... $33 ($2.5–$100) Laden, et al., (2006): ...... 3% discount rate ...... $89 ($7.7–$260) 7% discount rate ...... $80 ($6.9–$240) Climate-related Co-Benefits (3% discount rate) ...... $0.36

Monetized Total Co-Benefits

Pope, et al., (2002): ...... 3% discount rate ...... $37 ($3.2–$110) 7% discount rate ...... $33 ($2.9–$100) Laden, et al., (2006): ...... 3% discount rate ...... $90 ($8.0–$260) 7% discount rate ...... $81 ($7.3–$240) a Values rounded to two significant figures. Co-benefits from reducing exposure to ozone, other criteria pollutants, and HAP, as well as reduc- ing visibility impairment and ecosystem effects are not included here.

Our best estimate for the monetized When estimating the human health harmonization. Each agency shall also total health and climate co-benefits of benefits and compliance costs in Table seek to identify, as appropriate, means this rule in 2016 at a 3 percent discount 2 of this preamble, the EPA applied to achieve regulatory goals that are rate is between $37 billion and $90 methods and assumptions consistent designed to promote innovation.’’ We billion or between $33 billion and $81 with the state-of-the-science for human recognize that the utility sector faces a billion (2007$) at a 7 percent discount health impact assessment, economics variety of requirements, including ones rate. These estimates account for the and air quality analysis. The EPA under CAA section 110(a)(2)(D) dealing quantified health and climate benefits applied its best professional judgment with the interstate transport of described in Table 11. in performing this analysis and believes emissions contributing to ozone and PM XIII. Statutory and Executive Order that these estimates provide a air quality problems, with coal Reviews reasonable indication of the expected combustion wastes, and with the benefits and costs to the nation of this implementation of CWA section 316(b). A. Executive Order 12866, Regulatory rulemaking. The RIA available in the In developing today’s final rule, the EPA Planning and Review and Executive docket describes in detail the empirical recognizes that it needs to approach Order 13563, Improving Regulation and basis for the EPA’s assumptions and these rulemakings in ways that allow Regulatory Review characterizes the various sources of the industry to make practical Under EO 12866 (58 FR 51735; uncertainties affecting the estimates investment decisions that minimize October 4, 1993), this action is an below. In doing what is laid out above costs in complying with all of the final ‘‘economically significant regulatory in this paragraph, the EPA adheres to rules, while still achieving the action’’ because it is likely to have an EO 13563, ‘‘Improving Regulation and fundamentally important environmental annual effect on the economy of $100 Regulatory Review,’’ (76 FR 3821; and public health benefits that underlie million or more or adversely affect in a January 18, 2011), which is a the rulemakings. material way the economy, a sector of supplement to EO 12866. A summary of the monetized costs, the economy, productivity, competition, In addition to estimating costs and benefits, and net benefits for the final jobs, the environment, public health or benefits, EO 13563 focuses on the rule at discount rates of 3 percent and safety, or state, local, or tribal importance of a ‘‘regulatory system 7 percent is in Table 2 of this preamble. governments or communities. [that] * * * promote[s] predictability For more information on the analysis, Accordingly, the EPA submitted this and reduce[s] uncertainty’’ and that please refer to the RIA for this action to the OMB for review under ‘‘identify[ies] and use[s] the best, most rulemaking, which is available in the Executive Orders 12866 and 13563 and innovative, and least burdensome tools docket. any changes in response to OMB for achieving regulatory ends.’’ In B. Paperwork Reduction Act recommendations have been addition, EO 13563 states that ‘‘[i]n documented in the docket for this developing regulatory actions and The information collection action. For more information on the identifying appropriate approaches, requirements in this rule have been costs and benefits for this rule, please each agency shall attempt to promote submitted for approval to the OMB refer to Table 2 of this preamble. such coordination, simplification, and under the Paperwork Reduction Act, 44

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U.S.C. 3501 et seq. The Information might entail. The EPA’s estimate for the hours per year at a total labor cost of Collection Request (ICR) document required notification, reports, and $49.1 million per year, annualized prepared by the EPA has been assigned records, including the root cause capital costs of $81.9 million, and EPA ICR number 2137.06. analysis, associated with a single annual operating and maintenance costs The information collection incident totals approximately totals of $76.5 million. This estimate includes requirements are not enforceable until $3,141, and is based on the time and initial and annual performance tests, OMB approves them. The information effort required of a source to review semiannual excess emission reports, requirements are based on notification, relevant data, interview plant developing a monitoring plan, recordkeeping, and reporting employees, and document the events notifications, and recordkeeping. All requirements in the NESHAP General surrounding a malfunction that has burden estimates are in 2007 dollars and Provisions (40 CFR part 63, subpart A), caused an exceedance of an emission represent the most cost effective which are mandatory for all operators limit. The estimate also includes time to monitoring approach for affected subject to national emission standards. produce and retain the record and facilities. Burden is defined at 5 CFR These recordkeeping and reporting reports for submission to EPA. The EPA 1320.3(b). requirements are specifically authorized provides this illustrative estimate of this An Agency may not conduct or by CAA section 114 (42 U.S.C. 7414). burden, because these costs are only sponsor, and a person is not required to All information submitted to the EPA incurred if there has been a violation, respond to, a collection of information pursuant to the recordkeeping and and a source chooses to take advantage unless it displays a currently valid OMB reporting requirements for which a of the affirmative defense. control number. The OMB control claim of confidentiality is made is The EPA provides this illustrative numbers for our regulations are listed in safeguarded according to Agency estimate of this burden because these 40 CFR part 9. When this ICR is policies set forth in 40 CFR part 2, costs are only incurred if there has been approved by OMB, the Agency will subpart B. This final rule requires a violation and a source chooses to take publish a technical amendment to 40 maintenance inspections of the control advantage of the affirmative defense. CFR part 9 in the Federal Register to devices but would not require any Given the variety of circumstances display the OMB control number for the notifications or reports beyond those under which malfunctions could occur, approved information collection required by the General Provisions. The as well as differences among sources’ requirements contained in this final recordkeeping requirements require operation and maintenance practices, rule. only the specific information needed to we cannot reliably predict the severity C. Regulatory Flexibility Act, as determine compliance. and frequency of malfunction-related Amended by the Small Business When a malfunction occurs, sources excess emissions events for a particular Regulatory Enforcement Fairness Act of must report them according to the source. It is important to note that the 1996 (SBREFA), 5 U.S.C. 601 et seq. applicable reporting requirements of 40 EPA has no basis currently for CFR part 63, subpart UUUUU. An estimating the number of malfunctions The Regulatory Flexibility Act (RFA) affirmative defense to civil penalties for that would qualify for an affirmative generally requires an agency to prepare exceedances of emission limits that are defense. Current historical records a regulatory flexibility analysis of any caused by malfunctions is available to a would be an inappropriate basis, as rule subject to notice and comment source if it can demonstrate that certain source owners or operators previously rulemaking requirements under the criteria and requirements are satisfied. operated their facilities in recognition Administrative Procedure Act or any The criteria ensure that the affirmative that they were exempt from the other statute unless the agency certifies defense is available only where the requirement to comply with emissions that the rule will not have a significant event that causes an exceedance of the standards during malfunctions. Of the economic impact on a substantial emission limit meets the narrow number of excess emissions events number of small entities. Small entities definition of malfunction in 40 CFR 63.2 reported by source operators, only a include small businesses, small (sudden, infrequent, not reasonable small number would be expected to organizations, and small governmental preventable, and not caused by poor result from a malfunction (based on the jurisdictions. maintenance and or careless operation) definition above), and only a subset of For purposes of assessing the impacts and where the source took necessary excess emissions caused by of today’s rule on small entities, small actions to minimize emissions. In malfunctions would result in the source entity is defined as: (1) A small business addition, the source must meet certain choosing to assert the affirmative that is an electric utility producing 4 notification and reporting requirements. defense. Thus, we believe the number of billion kilowatt-hours or less as defined For example, the source must prepare a instances in which source operators by NAICS codes 221122 (fossil fuel-fired written root cause analysis and submit might be expected to avail themselves of electric utility steam generating units) a written report to the Administrator the affirmative defense will be and 921150 (fossil fuel-fired electric documenting that it has met the extremely small. utility steam generating units in Indian conditions and requirements for For this reason, we estimate no more country); (2) a small governmental assertion of the affirmative defense. than two such occurrences for all jurisdiction that is a government of a For this rule, EPA is adding sources subject to 40 CFR part 63, city, county, town, school district or affirmative defense to the estimate of subpart UUUUU over the 3-year period special district with a population of less burden in the ICR. To provide the covered by this ICR. We expect to gather than 50,000; and (3) a small public with an estimate of the relative information on such events in the organization that is any not-for-profit magnitude of the burden associated future, and will revise this estimate as enterprise which is independently with an assertion of the affirmative better information becomes available. owned and operated and is not defense position adopted by a source, The annual monitoring, reporting, and dominant in its field. the EPA has provided administrative record-keeping burden for this Pursuant to RFA section 603, the EPA adjustments to this ICR that shows what collection (averaged over the first 3 prepared an initial regulatory flexibility the notification, recordkeeping, and years after the effective date of the analysis (IRFA) for the proposed rule reporting requirements associated with standards) is estimated to be $207.6 and convened a Small Business the assertion of the affirmative defense million. This includes 700,296 labor Advocacy Review Panel to obtain advice

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and recommendations of representatives 3. Summary of Issues Raised During the Response: The RFA requires that of the regulated small entities. A Public Comment Process on the IRFA SBAR Panels collect advice and detailed discussion of the Panel’s advice The EPA received a number of recommendations from SERs on the and recommendations is found in the comments related to the Regulatory issues related to: Panel Report (EPA–HQ–OAR–2009– Flexibility Act during the public —The number and description of the 0234–2921). A summary of the Panel’s comment process. A consolidated small entities to which the proposed recommendations is presented at 76 FR version of the comments received is rule will apply; 24975. reproduced below. These comments can —The projected reporting, As required by RFA section 604, we also be found in their entirety in the recordkeeping and other compliance also prepared a final regulatory response to comment document in the requirements of the proposed rule; flexibility analysis (FRFA) for the final docket. —Duplication, overlap or conflict rule. The FRFA addresses the issues Comment: Several commenters between the proposed rule and other expressed concern with the SBAR federal rules; and raised by public comments on the IRFA, panel. Some believe Small Entity —Alternatives to the proposed rule that which was part of the proposal of this Representatives (SERs) were not accomplish the stated statutory rule. The FRFA is summarized below provided with regulatory alternatives objectives and minimize any and in the RIA. including descriptions of significant significant economic impact on small 1. Reasons Why Action Is Being Taken regulatory options, differing timetables, entities. or simplifications of compliance and The RFA does not require a covered In 2000, the EPA made a finding that reporting requirements, and agency to create or assemble it was appropriate and necessary to subsequently were not presented with information for SERs or for the regulate coal- and oil-fired EGUs under an opportunity to respond. One government panel members. Although CAA section 112 and listed EGUs commenter believes the EPA’s formal CAA section 609(b)(4) requires that the pursuant to CAA section 112(c). On SBAR Panel notification and subsequent government Panel members review any March 29, 2005 (70 FR 15994), the EPA information provided by the EPA to the material the covered agency has published a final rule (2005 Action) that Panel did not include information on prepared in connection with the RFA, removed EGUs from the list of sources the potential impacts of the rule as the law does not prescribe the materials for which regulation under CAA section required by CAA section 609(b)(1). to be reviewed. The EPA’s policy, as 112 was required. That rule was Additional commenters suggested that reflected in its RFA guidance, is to published in conjunction with a rule the EPA’s rulemaking schedule put provide as much information as requiring reductions in emissions of Hg pressure on the SBAR Panel through the possible, given time and resource from EGUs pursuant to CAA section abbreviated preparation for the Panel. constraints, to enable an informed Panel 111, i.e., CAMR, May 18, 2005, 70 FR Commenters also expressed concerns discussion. In this rulemaking, because 28606). The 2005 Action was vacated on that the EPA did not provide of a court-ordered deadline, the EPA February 8, 2008, by the U.S. Court of participants more than cursory was unable to hold a pre-panel meeting Appeals for the District of Columbia background information on which to but still provided SERs with the Circuit. As a result of that vacatur, base their comments. One commenter information available at the time, held CAMR was also vacated and EGUs stated that the EPA did not provide a standard Panel Outreach meeting to remain on the list of sources that must deliberative materials, including draft collect verbal advice and be regulated under CAA section 112. proposed rules or discussions of recommendations from SERs, and This action provides the EPA’s final regulatory alternatives, to the SBAR provided the standard 14-day written NESHAP and NSPS for EGUs. Panel members. One commenter stated comment period to SERs. The EPA the SBAR Panel Report does not meet received substantial input from the 2. Statement of Objectives and Legal the statutory obligation to recommend SERs, and the Panel report describes Basis for Final Rules less burdensome alternatives. The recommendations made by the Panel on commenter suggested the EPA panel measures the Administrator should The MATS will protect air quality and members declined to make consider that would minimize the promote public health by reducing recommendations that went further than economic impact of the proposed rule emissions of HAP. In the December consideration or investigation of broad on small entities. The EPA complied 2000 regulatory determination, the EPA regulatory alternatives, with the with the RFA. In addition, we met with made a finding that it was appropriate exception of those recommendations in representatives of small businesses, and necessary to regulate EGUs under which the EPA rejected alternative small rural cooperatives, and small CAA section 112. The February 2008 interpretations of the CAA section 112 governments a number of times during vacatur of the 2005 Action reverted the and relevant court cases. Two stated the regulatory development process to status of the rule to the December 2000 that the EPA did not respond to the discuss their issues and concerns regulatory determination. Section concerns of the small business regarding the proposed MATS rule for 112(n)(1)(A) of the CAA and the 2000 community, the SBA, or OMB, ignoring EGUs. determination do not differentiate concerns expressed by the SER Comment: One commenter requested between EGUs located at major versus panelists. One commenter believes the that the EPA work with utilities such area sources of HAP. Thus, the NESHAP EPA failed to convene required that new regulations are as flexible and for EGUs will regulate units at both meetings and hearings with affected cost efficient as possible. major and area sources. Major sources of parties as required by law for small Response: In developing the final HAP are those that have the potential to business entities. One commenter stated rule, the EPA has considered all emit at least 10 tons per year (tpy) of that the SERs’ input is very important information provided prior to, as well as any one HAP or at least 25 tpy of any because more than 90 percent of public in response to, the proposed rule. The combination of HAP. Area sources are power utility systems meet the EPA has endeavored to make the final any stationary sources of HAP that are definition and qualify as small regulations flexible and cost-efficient not major sources. businesses under the SBREFA. while adhering to the requirements of

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the CAA. The final rule includes a public power is critical to communities, onerous monitoring requirements; number of flexibilities, such as those jobs, economic viability and electric however, the EPA does not recognize related to monitoring requirements, that reliability. A generating and that small and LEEs also need and merit will lower costs and simplify transmissions electric cooperative more flexible and achievable pollution compliance for small businesses and which qualifies as a small entity control requirements. The commenter local governments. believes the rule will ultimately result notes that the capital costs for emissions Comment: One commenter was in increased electricity costs to its control at small utility units is concerned about the ability of small members and will negatively impact the disproportionately high due to entities or nonprofit utilities such as economies of the primarily rural areas inefficiencies in Hg removal, space those owned and/or operated by rural that they serve. Another commenter constraints for control technology electric co-op utilities, and municipal believes there is no legal or factual basis retrofits, and the fact that small units utilities to comply with the proposed for creating subcategories or weaker have fewer rate base customers across standards within 3 years. The standards for state, tribal, or municipal which to spread these costs. The commenter believes that the EPA governments or small entities that are commenter cites the Michigan disregarded the SER panelists who operating obsolete units, particularly Department of Environmental Quality explained that under these current given the current market situation and report titled ‘‘Michigan’s Mercury economic conditions they have applicable equitable factors. The Electric Utility Workgroup, Final Report constraints on their ability to raise commenter suggests both the EPA’s and on Mercury Emissions from Coal-Fired capital for the construction of control SBA’s analyses focus exclusively on the Power Plants,’’ (June 2005). The projects and to acquire the necessary effects on entities causing HAP commenter notes that the EPA has resources in order to meet a 3-year emissions and primarily on those addressed such concerns previously, compliance deadline. Two commenters operating obsolete EGUs, and fail to citing the RIA for the 1997 8-hour ozone expressed concern that smaller utilities consider either impacts on downwind standard. The commenter also suggests and those in rural areas will be unable businesses and governments or the smaller utility systems generally have to get vendors to respond to their positive impacts on small entities and less capital to invest in pollution control requests for proposals, because they will governments owning and operating than larger, investor-owned systems, be able to make more money serving competing, clean and modern EGUs. due to statutory inability to borrow from larger utilities. Response: The EPA disagrees with the the private capital markets, statutory Response: The preamble to the commenters’ belief that the impacts on debt ceilings, limited bonding capacity, proposed rule (76 FR 25054; May 3, smaller generating units were not borrowing limitations related to fiscal 2011) provides a detailed discussion of adequately considered when developing strain posed by other, non- how the EPA determined compliance the rule. The EPA determined the environmental factors, and other times for the proposed (and final) rule. number of potentially impacted small limitations. The EPA has provided pursuant to CAA entities and assessed the potential Response: The EPA acknowledges section 112(i)(3)(A) the maximum 3-year impact of the proposed action on small that the rule contains reduced period for sources to come into entities, including municipal units. A monitoring requirements for existing compliance. Sources may also seek a 1- similar assessment was conducted in units that qualify as LEEs. Although the year extension of the compliance period support of the final action. Specifically, EPA does not believe that reduced from their Title V permitting authority the EPA estimated the incremental net pollution control requirements are if the source needs that time to install annualized compliance cost, which is a warranted for LEEs, including small controls. See CAA section 112(i)(3)(B). If function of the change in capital and entity LEEs, we believe that flexible and the situation described by commenters operating costs, fuel costs, and change achievable pollution control (i.e., where small entities or nonprofit in revenue. The projected compliance requirements are promoted through utilities constraints on ability to raise cost was considered relative to the alternative standards, alternative capital for construction of control projected revenue from generation. compliance options, and emissions projects and to acquire necessary Thus, the EPA’s analysis accounts not averaging as a means of demonstrating resources) results in the source needing only for the additional costs these compliance with the standards for additional time to install controls, they entities face resulting from compliance, existing EGUs. would be in a position to request the 1- but also the impact of higher electricity Comment: One commenter believes year extension. prices. The EPA evaluated suggestions that the EPA should develop more Comment: Several commenters from SERs, including subcategorization limited monitoring requirements for believe the EPA did not adequately recommendations. In the preamble to small EGUs. The commenter notes small consider the disproportionately large the proposed rule, the EPA explains entities do not possess the monetary impact on smaller generating units. The that, normally, any basis for resources, manpower, or technical commenters note the diseconomies in subcategorizing must be related to an expertise needed to operate cutting-edge scale for pollution controls for such effect on emissions, rather than some monitoring techniques such as Hg units. One commenter noted the rule difference which does not affect CEMS and PM CEMS. The commenter will create a more serious compliance emissions performance. The EPA does notes the EPA could have identified hurdle for small communities that not see a distinction between emissions monitoring alternatives to the SER panel depend on coal-fired generation to meet from smaller generating units versus for consideration. their base load demand. The commenter larger units. The EPA acknowledges the Response: The EPA provided notes that by not subcategorizing units, comment that there is no legal or factual monitoring alternatives to using PM the EPA is dictating a fuel switch due basis for creating subcategories or CEMS, HCl CEMS, and Hg CEMS in its to the disproportionately high cost on weaker standards for state, tribal, or proposed standards and in this final small communities. The other municipal governments or small entities rule. The continuous compliance commenter believes the MACT and that are operating obsolete units. alternatives are available to all affected NSPS standards are unachievable by Comment: One commenter notes that sources, including small entities. As going too far without really considering the EPA recognizes LEEs in the rule alternatives to the use of PM CEMS and the impacts on small municipal units, as such that they should receive less HCl CEMS, sources are allowed to

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conduct additional performance testing. references the SBAR Panel Report area source EGUs be distinguished from Sorbent trap monitoring is allowed in suggestion provided in the preamble of major-source EGUs and the EPA’s lieu of Hg CEMS. the proposed rule that the EPA consider reasons for not making that distinction Comment: Several commenters developing an area source vs. major (76 FR 25020–25021; May 3, 2011). believe the EPA has not sufficiently source distinction for the source The EPA also disagrees with the complied with the requirements of the category and the EPA’s response. suggestion that the Agency pursue an RFA or adequately considered the Another commenter is concerned that extension of the timeline for final impact this rulemaking would have on the recommendations made by the SER rulemaking such that the SBAR Panel small entities. One commenter believes participants were ignored and not can be reconvened and a new IRFA can the EPA has not engaged in meaningful discussed in the rulemaking. be prepared and released for public outreach and consultation with small Specifically, the commenter notes the comment prior to the final rulemaking. entities and therefore recommends that EPA did not discuss subcategorizing by The EPA entered into a Consent Decree the EPA seek to revise the court-ordered age, type of plant, fuel, physical space to resolve litigation alleging that the deadlines to which this rulemaking is constraints or useful anticipated life of EPA failed to perform a non- subject, re-convene the SBAR panel, the plant. Nor did the EPA establish discretionary duty to promulgate CAA prepare a new initial regulatory GACT for smaller emitters to alleviate section 112(d) standards for EGUs. See flexibility analysis (IRFA), and issue it regulatory costs and operational American Nurses Ass’n v. EPA, 08–2198 for additional public comment prior to difficulties. A commenter believes it is (D.D.C.). That Decree required the EPA to sign the final MATS rule by final rulemaking. The commenter likely that different numerical or work November 16, 2011, unless the agency believes the IRFA does not sufficiently practice standards are appropriate for sought to extend the deadline consistent consider impacts on small entities as area sources of HAP. Response: The EPA disagrees with with the requirements of the identified in the SBAR Panel Report. one commenter’s assertion that the modification provision of the Consent The commenter believes it is not agency has not complied with the Decree. The EPA and Plaintiffs apparent that the EPA considered the requirements of the RFA. The EPA stipulated to a 30-day extension recommendations of the Panel. The complied with both the letter and spirit consistent with the modification commenter believes the description of of the RFA, notwithstanding the provisions of the Consent Decree and significant alternatives in the IRFA is constraints of the court-ordered the rule must be signed no later than almost entirely quoted from the SBAR deadline. For example, the EPA notified December 16, 2011. If plaintiffs in the Panel Report, which the commenter the Chief Counsel for Advocacy of the American Nurses litigation objected to does not believe is an adequate SBA of its intent to convene a Panel; an additional extension request, which substitute for the EPA’s own analysis of compiled a list of SERs for the Panel to we believe would have been likely, the alternatives. The commenter also notes consult with; and convened the Panel. Agency would have had to file a motion the EPA does not discuss the potential The Panel met with SERs to collect their with the Court seeking an extension of impacts of its decisions on small entities advice and recommendations; reviewed the deadline. Consistent with governing or the impacts of possible flexibilities. the EPA materials; and drafted a report case law, the Agency would have been Where the EPA does consider regulatory of Panel findings. The EPA further required to demonstrate in its motion alternatives in principle, the commenter disagrees with the commenter’s for extension that it was impossible to believes it does not provide sufficient assertion that the EPA’s IRFA does not finalize the rule by the deadline support for its decisions to understand sufficiently consider impacts on small provided in the Consent Decree. See on what basis the EPA rejected entities. The EPA’s IRFA, which is Sierra Club v. Jackson, Civil Action No. alternatives that may or may not have included in chapter 10 of the RIA for the 01–1537 (D.D.C.) (Opinion of the Court reduced burden on small entities while proposed rule, addresses the statutorily denying EPA’s motion to extend a meeting the stated objectives of the rule. required elements of an IRFA, such as consent decree deadline). The EPA Additionally, the commenter notes that the economic impact of the proposed negotiated a 30-day extension and was the EPA did not evaluate the economic rule on small entities and the Panel’s able to complete the rule by December or environmental impacts of significant findings. 16, 2011; accordingly, the Agency had alternatives to the proposed rule. One The EPA disagrees with the comment no basis for seeking a further extension commenter believes that the EPA’s that recommendations made by the of time. stated reasons for declining to specify or SERs were not considered or discussed A detailed description of the changes analyze an area source standard are in the proposed rulemaking such as made to the rule since proposal, inadequate under the RFA. The recommendations regarding including those made as a result of commenter believes the EPA must give subcategorization and separate GACT feedback received during the public serious consideration to regulatory standards for area sources. The comment process can be found in alternatives that accomplish the stated preamble to the proposed standards sections VI (NESHAP) and X (NSPS) of objectives of the CAA while minimizing includes a detailed discussion of how this preamble. Changes explained in the any significant economic impacts on the EPA determined which identified sections include those related small entities and that the EPA has a subcategories and sources would be to applicability; subcategorization; work duty to specify and analyze this option regulated (76 FR 25036–25037; May 3, practices; periods of startup, shutdown, or to more clearly state its policy 2011). In that discussion, the EPA and malfunction; initial testing and reasons for excluding serious explains the rationale for its proposed compliance; continuous compliance; consideration of a separate standard for subcategories based on five unit design and notification, recordkeeping, and area sources. A commenter believes the types. In addition, the EPA reporting. EPA did not fully consider the acknowledges the subcategorization subcategorization of sources such as suggestions from the SERs and explains 4. Description and Estimate of the boilers designed to burn lignite coals its reasons for not subcategorizing on Affected Small Entities versus other fossil fuels, especially in those bases. The preamble to the For the purposes of assessing the regard to non-mercury metal and acid proposed standards also includes a impacts of MATS on small entities, a gas emissions. The commenter discussion of the SERs’ suggestion that small entity is defined as:

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(1) A small business according to the to be operating and, thus, are not significantly under MATS to meet Small Business Administration size projected to face the costs of compliance electricity demand in its region. standards by the North American with the rule. After omitting entities for Excluding this unit, the total cost Industry Classification System (NAICS) the reasons above, the EPA identified a impacts across all entities would be category of the owning entity. The range total of 82 potentially affected small roughly $175 million. Changes in of small business size standards for entities that are affiliated with 102 compliance behavior for this small electric utilities is 4 billion kilowatt EGUs. group of units, in particular the one unit hours (kWh) of production or less; 5. Compliance Cost Impacts which operates at a higher capacity (2) A small government jurisdiction factor, has a substantial impact on total that is a government of a city, county, The number of potentially affected costs as their increased generation town, district, or special district with a small entities by ownership type and revenues offsets a large portion of the population of less than 50,000; and potential impacts of MATS are compliance costs. (3) A small organization that is any presented in Chapter 7 of the RIA and The most significant components of not for profit enterprise that is summarized here. The EPA estimated incremental costs to these entities are the annualized net compliance cost to independently owned and operated and changes in electricity revenues, small entities to be approximately $106 is not dominant in its field. followed by the increased capital and The EPA examined the potential million in 2015 (2007$). operating costs for retrofits. Capital and economic impacts to small entities The EPA assessed the economic and operating costs increase across all associated with this rulemaking based financial impacts of the final rule using ownership types, but the direction of on assumptions of how the affected the ratio of compliance costs to the entities will install control technologies value of revenues from electricity changes in electricity revenues varies in compliance with MATS. This generation, and our results focus on among ownership types. All ownership analysis does not examine potential those entities for which this measure types, with the exception of private indirect economic impacts associated could be greater than 1 percent or 3 entities, experience a net gain in with this rule, such as employment percent. Of the 82 small entities electricity revenues under the MATS, effects in industries providing fuel and identified, The EPA’s analysis shows 40 unlike projections from the EPA’s pollution control equipment, or the entities may experience compliance modeling during the proposal, where potential effects of electricity price costs greater than 1 percent of base only municipals benefitted from higher increases on industries and households. generation revenues in 2015, and 35 electricity revenues. The change in The EPA used Velocity Suite’s Ventyx may experience compliance costs electricity revenue takes into account data as a basis for identifying plant greater than 3 percent of base revenues. both the profit lost from units that do ownership and compiling the list of Also, all generating capacity at 3 small not operate under the policy case and potentially affected small entities. The entities is projected to be uneconomic to the difference in revenue for operating Ventyx dataset contains detailed maintain. In this analysis, the cost of units under the policy case. According ownership and corporate affiliation withdrawing a unit as uneconomic is to the EPA’s modeling, an estimated 274 information. The analysis focused only estimated as the base case profit that is MW of capacity owned by small entities on those EGUs affected by the rule, forgone by not operating under the are considered uneconomic to operate which includes units burning coal, oil, policy case. Because 35 of the 82 total under the policy case, resulting in a net petroleum coke, or coal refuse as the units, or more than 40 percent, are loss of $13 million (in 2007$) in profits. primary fuel, and excludes any estimated to incur compliance cost On the other hand, many operating combustion turbine units or EGUs greater than 3 percent of base revenues, units actually increase their electricity burning natural gas. Also, because the the EPA has concluded that it cannot revenue due to higher electricity prices rule does not affect combustion units certify that there will be no significant under MATS. In addition, as mentioned with an equivalent electricity generating economic impact on a substantial above, the EPA’s modeling indicates one capacity up to 25 MW, small entities number of small entities (SISNOSE) for unit finds it economical to increase its that do not own at least one combustion this rule. Results for small entities capacity factor significantly under the unit with a capacity greater than 25 MW discussed here do not account for the policy case which results in were removed from the dataset. For the reality that electricity markets are significantly higher revenues offsetting affected units remaining, boiler and regulated in parts of the country. the costs. generator capacity, heat input, Entities operating in regulated or cost- 6. Description of Steps To Minimize generation, and emissions data were of-service markets should be able to Impacts on Small Entities aggregated by owner and then by parent recover all of their costs of compliance company. Entities with more than 4 through rate adjustments. Consistent with the requirements of billion kWh of annual electricity Note that the estimated costs for small the RFA and SBREFA, the EPA has generation were removed from the list, entities are significantly lower than taken steps to minimize the significant as were municipal owned entities with those estimated by the EPA for the economic impact on small entities. a population greater than 50,000. For MATS proposal (which were $379 Because this rule does not affect units cooperatives, investor owned utilities, million). This is driven by a small group with a generating capacity of less than and subdivisions that generate less than of units (less than 6 percent) which 25 MW, small entities that do not own 4 billion kWh of electricity annually but were projected to be uneconomic to at least one generating unit with a which may be part of a large entity, operate under the proposal (and hence capacity greater than 25 MW are not additional research on power sales, incurred lost profits due to lost subject to the rule. According to the operating revenues, and other business electricity revenues), but are now EPA’s analysis, among the coal- and oil- activities was performed to make a final projected to continue their operations fired EGUs (i.e., excluding combined determination regarding size. Finally, under MATS. In addition, the EPA’s cycle gas turbines and gas combustion small entities for which the IPM does modeling indicates one unit that would turbines) about 26 potentially small not project generation in 2015 in the have operated at a low capacity factor entities only own EGUs with a capacity base case were omitted from the under the base case would find it less than or equal to 25 MW, and none analysis because they are not projected economical to increase its generation of those entities are subject to the final

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rule based on the statutory definition of emission limits selected as the MACT As required by SBREFA section 212, potentially regulated units. floors adequately represent the level of the EPA also is preparing a Small Entity For units affected by the proposed emissions actually achieved by the Compliance Guide to help small entities rule, the EPA considered a number of average of the units in the top 12 comply with this rule. Small entities comments received, both during the percent, considering operational will be able to obtain a copy of the Small Business Advocacy Review variability of those units. Small Entity Compliance guide at the (SBAR) Panel and the public comment e. Alternatives not adopted. The EPA following Web site: http://www.epa.gov/ period. While none of the alternatives did not adopt several of the suggestions airquality/powerplanttoxics/ adopted is specifically applied to small posed either during the SBAR Panel or actions.html. entities, the EPA believes these public comment period. The EPA did modifications will make compliance not propose a percent reduction D. Unfunded Mandates Reform Act of less onerous for all regulated units, standard as an alternative to the 1995 including those owned by small entities. concentration-based MACT floor. The Title II of the UMRA of 1995, Public a. Work practice standards. The EPA percent reduction format for Hg and Law 104–4, establishes requirements for proposed numerical emission standards other HAP emissions would not have federal agencies to assess the effects of that would apply at all times, including addressed the EPA’s consideration of their regulatory actions on state, local, during periods of startup and shutdown. coal preparation practices that remove and tribal governments and the private After reviewing comments and other Hg and other HAP before firing. Also, to sector. Under UMRA section 202, we data regarding the nature of these account for the coal preparation generally must prepare a written periods of operation, the EPA is practices, sources would be required to statement, including a cost-benefit finalizing a work practice standard for track the HAP concentrations in coal analysis, for proposed and final rules periods of startup and shutdown. The from the mine to the stack, and not just with ‘‘Federal mandates’’ that may EPA is also finalizing work practice before and after the control device(s), result in expenditures to state, local, standards for organic HAP from all and such an approach would be difficult and tribal governments, in the aggregate, subcategories of EGUs. Descriptions of to implement and enforce. Furthermore, or to the private sector, of $100 million the work practice requirements for the EPA does not believe the percent or more in any 1 year. Before startup and shutdown, as well as reduction standard is in line with the promulgating a rule for which a written organic HAP and limited-use liquid oil- Court’s interpretation of the CAA statement is needed, UMRA section 205 fired EGUs, can be found in section section 112 requirements. Even if we generally requires us to identify and VI.D–E. of the preamble. believed it was appropriate to establish consider a reasonable number of b. Continuous compliance and a percent reduction standard, we do not regulatory alternatives and adopt the notification, record-keeping, and have the data necessary to establish least costly, most cost-effective or least reporting. The final rule greatly percent reduction standards for HAP, as burdensome alternative that achieves simplifies the continuous compliance explained further in the response to the objectives of the rule. The requirements and provides two basic comments document. provisions of UMRA section 205 do not approaches for most situations: use of The EPA determined not to establish apply when they are inconsistent with continuous monitoring and periodic GACT standards for area sources for a applicable law. Moreover, UMRA testing. The frequency of periodic number of reasons. The data show that section 205 allows us to adopt an testing has been decreased from similar HAP emissions and control alternative other than the least costly, monthly in the proposal to quarterly in technologies are found on both major most cost-effective or least burdensome the final rule. In addition to simplifying and area sources greater than 25 MW, alternative if the Administrator compliance, the EPA believes these and some large units are synthetic area publishes with the final rule an changes considerably reduce the overall sources. In fact, because of the explanation why that alternative was burden associated with recordkeeping significant number of well-controlled not adopted. Before we establish any and reporting. These changes to the EGUs of all sizes, we believe it would regulatory requirements that may final rule are described in more detail in be difficult to make a distinction significantly or uniquely affect small Section VI.G–H of this preamble. between MACT and GACT. Moreover, governments, including tribal c. Subcategorization. The Small Entity the EPA believes the standards for area governments, we must develop a small Representatives on the SBAR Panel source EGUs should reflect MACT, government agency plan under UMRA were generally supportive of rather than GACT, because there is no section 203. The plan must provide for subcategorization and suggested a essential difference between area source notifying potentially affected small number of additional subcategories the and major source EGUs with respect to governments, enabling officials of EPA should consider when developing emissions of HAP. affected small governments to have the final rule. Although it was not The EPA determined not to exercise meaningful and timely input in the consistent with the statute to adopt the its discretionary authority to establish development of regulatory proposals proposed subcategories, the EPA health-based emission standards for HCl with significant federal maintained the existing subcategories and other HAP acid gases. Given the intergovernmental mandates, and and split the ‘‘liquid oil-fired units’’ limitations of the currently available informing, educating, and advising subcategory into three subcategories— information (e.g., the HAP mix where small governments on compliance with continental, non-continental units, and EGUs are located, and the cumulative the regulatory requirements. limited-use units. impacts of respiratory irritants from We have determined that this rule d. MACT floor calculations. As nearby sources), the environmental contains a federal mandate that may recommended by the EPA SBAR Panel effects of HCl and the other acid gas result in expenditures of $100 million or representative, the EPA established the HAP, and the significant co-benefits more for state, local, and tribal MACT floors using all the available ICR from reductions in criteria pollutants governments, in the aggregate, or the data that was received to the maximum the EPA determined that setting a private sector in any 1 year. extent possible consistent with the CAA conventional MACT standard for HCl Accordingly, we have prepared a requirements. The Agency believes this and the other acid gas HAP was the written statement entitled ‘‘Unfunded approach reasonably ensures that the appropriate course of action. Mandates Reform Act Analysis’’ under

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UMRA section 202 that is within the attacks, asthma attacks, and work-lost creation of productive jobs, and RIA and which is summarized below. days (i.e., days when employees are international competitiveness of the unable to work). Although we are U.S. goods and services, if we determine 1. Statutory Authority unable to monetize the benefits that accurate estimates are reasonably As discussed elsewhere in this associated with the HAP emissions feasible and that such effect is relevant preamble, the statutory authority for this reductions other than for Hg or all and material. rulemaking is CAA section 112. Title III benefits associated with Hg reductions, The nationwide economic impact of of the CAA Amendments was enacted to we are able to monetize the benefits this rule is presented in the RIA in the reduce nationwide air toxic emissions. associated with the PM2.5 and SO2 docket. This analysis provides estimates CAA section 112(b) lists the 188 emissions reductions. For SO2 and of the effect of this rule on some of the chemicals, compounds, or groups of PM2.5, we estimated the benefits categories mentioned above. chemicals deemed by Congress to be associated with health effects of PM but The results of the economic impact HAP. These toxic air pollutants are to be were unable to quantify all categories of analysis are summarized previously in regulated by NESHAP. benefits (particularly those associated this preamble. The results show that, CAA section 112(d) directs us to with ecosystem and visibility effects). relative to baseline, there will be an develop NESHAP which require Our estimates of the monetized benefits average 3.1 percent increase in existing and new major sources to in 2016 associated with the electricity price on average nationwide control emissions of HAP using MACT- implementation of the final rule range in 2016, with the range of increases based standards. This NESHAP applies from $37 billion to $90 billion (2007 from 1.3 percent to 6.3 percent in to all coal- and oil-fired EGUs. dollars) when using a 3 percent regions throughout the U.S., and a less In compliance with UMRA section discount rate or from $33 billion to $81 than 1 percent increase in natural gas 205(a), we identified and considered a billion (2007 dollars) when using a 7 price nationwide in 2016. The roughly reasonable number of regulatory percent discount rate). Our estimate of 3 percent incremental price effect of this alternatives. Additional information on costs is $9.6 billion (2007 dollars). For rule is small relative to the changes the costs and environmental impacts of more detailed information on the observed in the absolute levels of these regulatory alternatives were benefits and costs estimated for this electricity prices over the last 50 years, presented in the RIA for the rulemaking. rulemaking, refer to the RIA in the which have ranged from as much as 23 The regulatory alternative upon docket. percent lower (in 1969) to as much as which this rule is based represents the 23 percent higher (in 1982) than prices MACT floor for all regulated pollutants 3. Future and Disproportionate Costs observed in 2010.377 Power generation for all but one EGU subcategory for all The UMRA requires that we estimate, from coal-fired plants will fall by about but one regulated pollutant for that where accurate estimation is reasonably 2 percent nationwide in 2016. No region subcategory. These MACT floor-based feasible, future compliance costs of the U.S. is expected to experience a standards represent the least costly and imposed by this rule and any double-digit increase in retail electricity least burdensome alternative. Beyond- disproportionate budgetary effects. Our prices in 2015 or in any year later than the-floor emission limits for Hg are for estimates of the future compliance costs that, according to the Agency’s analysis, existing coal-fired EGUs in the of this rule are discussed previously in as a result of this rule. To put the subcategory for low rank virgin coal this preamble. electricity price effects in context, the EGUs. The EPA assessed the economic and roughly 3 percent incremental increase financial impacts of the rule on 2. Social Costs and Benefits in aggregate end-user electricity prices government-owned entities using the projected to occur over the next 4 years The RIA prepared for this rule ratio of compliance costs to the value of is about the same as the 3 percent including the Agency’s assessment of revenues from electricity generation, absolute average change in total end- costs and benefits is in the docket. and our results focus on those entities user electricity prices observed on an It is estimated that HAP would be for which this measure could be greater annual basis.378 Furthermore, the reduced by thousands of tons in 2015, than 1 percent or 3 percent of base roughly 3 percent incremental price relative to the base case, including revenues. The EPA projects that 42 effect of this rule is small relative to the reductions in HCl, HF, metallic HAP government entities will have changes observed in the absolute levels (including Hg), and several other compliance costs greater than 1 percent of electricity prices over the last 50 organic HAP from EGUs. Studies have of base generation revenue in 2016, and years, which have ranged from as much determined a relationship between 32 may experience compliance costs as 23 percent lower (in 1969) to as much exposure to certain of these HAP and greater than 3 percent of base revenues. as 23 percent higher (in 1982) than the onset of cancer; however, the Overall, 6 units owned by government prices observed in 2010.379 Even with Agency is unable to provide a entities are expected to retire. The most this rule in effect, electricity prices are monetized estimate of the HAP benefits significant components of incremental projected to be lower in 2015 and 2020 at this time. In addition, significant costs to these entities are the increased than they were in 2010.380 reductions in PM2.5 and SO2 will occur, capital and operating costs, followed by including approximately 53 thousand changes in electricity revenues. For 5. Consultation With Government tons of PM2.5 and over 1 million tons of more details on these results and the The UMRA requires that we describe SO2. These reductions will occur by methodology behind their estimation, the extent of the Agency’s prior 2016 and are expected to continue see the results included in chapter 7 of consultation with affected state, local, throughout the life of the affected the RIA. sources. The major health effect 377 EIA Annual Energy Outlook 2010 annual total 4. Effects on the National Economy associated with reducing PM2.5 and electricity prices from 1960 to 2010, Table 8–10. 378 PM2.5 precursors (such as SO2) is a The UMRA requires that we estimate EIA Annual Energy Outlook 2010 annual total electricity prices from 1960 t0 2010, Table 8–10. reduction in premature mortality. Other the effect of this rule on the national 379 Ibid. health effects associated with PM2.5 economy. To the extent feasible, we 380 Ibid., EIA AEO 2010, Table–10 for price levels; emission reductions include avoiding must estimate the effect on productivity, and Chapterr 3 of the RIA for electricity price cases of chronic bronchitis, heart economic growth, full employment, differential.

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and tribal officials, summarize the potentially would be subject to the developing the rule to permit them to officials’ comments or concerns, and requirements of the rule. As part of that have meaningful and timely input into summarize our response to those process, the EPA considered several its development. The EPA met with 10 comments or concerns. In addition, options, which are discussed previously national organizations representing state UMRA section 203 requires that we in this preamble. Those options and local elected officials to provide develop a plan for informing and included establishing emission limits, general background on the rule, answer advising small governments that may be establishing work practice standards, questions, and solicit input. In the final significantly or uniquely impacted by a establishing subcategories, and rule, EPA has provided flexibilities that regulatory action. Consistent with the consideration of monitoring options. will lower compliance costs for these intergovernmental consultation The regulatory alternative selected is a entities. The EPA also recognizes that provisions of UMRA section 204, the combination of the options considered municipalities may need a longer EPA initiated consultations with and includes provisions regarding a compliance timeframe because of governmental entities affected by this number of the recommendations required approval processes. resulting from the SBAR Panel process rule. The EPA invited the following 10 F. Executive Order 13175, Consultation as described below (see the Regulatory national organizations representing state and Coordination With Indian Tribal Flexibility Act discussion in this section and local elected officials to a meeting Governments held on October 27, 2010, in of the preamble for more detail). Subject to EO 13175 (65 FR 67249; Washington, DC: (1) National Governors E. Executive Order 13132, Federalism Association; (2) National Conference of November 9, 2000) the EPA may not State Legislatures, (3) Council of State Under EO 13132, the EPA may not issue a regulation that has tribal Governments, (4) National League of issue an action that has federalism implications, that imposes substantial Cities, (5) U.S. Conference of Mayors, (6) implications, that imposes substantial direct compliance costs, and that is not National Association of Counties, (7) direct compliance costs, and that is not required by statute, unless the federal International City/County Management required by statute, unless the federal government provides the funds Association, (8) National Association of government provides the funds necessary to pay the direct compliance Towns and Townships, (9) County necessary to pay the direct compliance costs incurred by tribal governments, or Executives of America, and (10) costs incurred by state and local the EPA consults with tribal officials Environmental Council of States. These governments, or the EPA consults with early in the process of developing the state and local officials early in the proposed regulation and develops a 10 organizations of elected state and process of developing the final action. tribal summary impact statement. local officials have been identified by The EPA has concluded that this Executive Order 13175 requires the EPA the EPA as the ‘‘Big 10’’ organizations action may have federalism to develop an accountable process to appropriate to contact for purpose of implications, because it may impose ensure ‘‘meaningful and timely input by consultation with elected officials. The substantial direct compliance costs on Tribal officials in the development of purposes of the consultation were to state or local governments, and the regulatory policies that have Tribal provide general background on the rule, federal government will not provide the implications.’’ answer questions, and solicit input from funds necessary to pay those costs. The EPA has concluded that this state/local governments. During the Accordingly, the EPA provides the action may have tribal implications. The meeting, officials asked clarifying following federalism summary impact EPA offered consultation with tribal questions regarding CAA section 112 statement as required by section 6(b) of officials early in the regulation requirements and central decision EO 13132. development process to permit them an points presented by the EPA (e.g., use of Based on estimates in the RIA, opportunity to have meaningful and surrogate pollutants to address HAP, provided in the docket, the final rule timely input. Consultation letters were subcategorization of source category, may have federalism implications sent to 584 tribal leaders and provided assessment of emissions variability). because the rule may impose information regarding the EPA’s They also expressed uncertainty with approximately $294 million in annual development of this rule and offered regard to how utility boilers owned/ direct compliance costs on an estimated consultation. At the request of the operated by state and local entities 96 state or local governments. tribes, three consultation meetings were would be impacted, as well as with Specifically, we estimate that there are held: December 7, 2010, with the Upper regard to the potential burden 80 municipalities, 5 states, and 11 Sioux Community of Minnesota; associated with implementing the rule political subdivisions (i.e., a public December 13, 2010, with Moapa Band of on state and local entities (i.e., burden district with territorial boundaries Paiutes, Forest County Potawatomi, to re-permit affected EGUs or update embracing an area wider than a single Standing Rock Sioux Tribal Council, existing permits). Officials requested, municipality and frequently covering and Fond du Lac Band of Chippewa; and the EPA provided, addresses more than one county for the purpose of January 5, 2011, with the Forest County associated with the 112 state and local generating, transmitting and distributing Potawatomi, and a representative from governments estimated to be potentially electric energy) that may be directly the National Tribal Air Association impacted by the rule. The EPA has not impacted by this final rule. Responses to (NTAA). In these meetings, the EPA received additional questions or the EPA’s 2010 ICR were used to presented the authority under the CAA requests from state or local officials. estimate the nationwide number of used to develop these rules and an Consistent with UMRA section 205, potentially impacted state or local overview of the industry and the the EPA has identified and considered governments. As previously explained, industrial processes that have the a reasonable number of regulatory this 2010 survey was submitted to all potential for regulation. Tribes alternatives. Because the potential coal- and oil-fired EGUs listed in the expressed concerns about the impact of existed for a significant impact for 2007 version of DOE/EIA’s ‘‘Annual EGUs in Indian country. Specifically, substantial number of small entities, the Electric Generator Report,’’ and ‘‘Power they were concerned about potential Hg EPA convened a SBAR Panel to obtain Plant Operations Report.’’ deposition and the impact on the water advice and recommendation of The EPA consulted with state and resources of the tribes, with particular representatives of the small entities that local officials in the process of concern about the impact on subsistence

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lifestyles for fishing communities, the III of this preamble. The protection adopted by voluntary consensus cultural impact of impaired water offered by this rule is particularly standards bodies. The NTTAA directs quality for ceremonial purposes, and the important for children, especially the the EPA to provide Congress, through economic impact on tourism. In light of developing fetus. As referenced in OMB, explanations when the Agency these concerns, the tribes expressed Chapter 4 of the RIA, ‘‘Mercury and decides not to use available and interest in an expedited implementation Other HAP Benefits Analysis,’’ children applicable voluntary consensus of the rule. Other concerns expressed by are more vulnerable than adults to many standards. tribes related to how the Agency would HAP emitted by EGUs due to This rulemaking involves technical consider variability in setting the differential behavior patterns and standards. The EPA cites the following standards, and the use of tribal-specific physiology. These unique standards in the final rule: EPA fish consumption data from the tribes in susceptibilities were carefully Methods 1, 2, 2A, 2C, 2F, 2G, 3A, 3B, our assessments. They were not considered in a number of different 4, 5, 5D, 17, 19, 23, 26, 26A, 29, 30B of supportive of using work practice ways in the analyses associated with 40 CFR part 60 and Method 320 of 40 standards as part of the rule, and asked this rulemaking, and are summarized in CFR part 63. Consistent with the the Agency to consider going beyond the RIA. We also estimate substantial NTTAA, the EPA conducted searches to the MACT floor to offer more protection health improvements for children in the identify voluntary consensus standards for the tribal communities. form of 130,000 fewer asthma attacks, in addition to these EPA methods. No In addition to these consultations, the 3,100 fewer emergency room visits due applicable voluntary consensus EPA also conducted outreach on this to asthma, 6,300 fewer cases of acute standards were identified for EPA rule through presentations at the bronchitis, and approximately 140,000 Methods 2F, 2G, 5D, and 19. The search National Tribal Forum in Milwaukee, fewer cases of upper and lower and review results have been WI; phone calls with the NTAA; and a respiratory illness. documented and are placed in the webinar for tribes on the proposed rule. docket for the proposed rule. The EPA specifically requested tribal H. Executive Order 13211, Actions The three voluntary consensus data that could support the appropriate Concerning Regulations That standards described below were and necessary analyses and the RIA for Significantly Affect Energy Supply, identified as acceptable alternatives to this rule. In addition, the EPA held Distribution, or Use EPA test methods for the purposes of individual consultations with the Executive Order 13211 (66 FR 28355; the final rule. Navajo Nation on October 12, 2011; as May 22, 2001) requires EPA to prepare The voluntary consensus standard well as the Gila River Indian and submit a Statement of Energy American National Standards Institute Community, Ak-Chin Indian Effects to the Administrator of the Office (ANSI)/American Society of Mechanical Community, and the Hopi Nation on of Information and Regulatory Affairs, Engineers (ASME) PTC 19–10–1981, October 14, 2011. These tribes OMB, for actions identified as ‘‘Flue and Exhaust Gas Analyses [part expressed concerns about the impact of ‘‘significant energy actions.’’ This 10, Instruments and Apparatus]’’ is the rule on the Navajo Generating action, which is a significant regulatory cited in the final rule for its manual Station (NGS), the impact on the cost of action under EO 12866, is likely to have method for measuring the O2, CO2, and the water allotted to the tribes from the a significant adverse effect on the CO content of exhaust gas. This part of Central Arizona Project (CAP), the supply, distribution, or use of energy. ANSI/ASME PTC 19–10–1981 is an impact on tribal revenues from the coal We have prepared a Statement of Energy acceptable alternative to Method 3B. mining operations (i.e., assumptions Effects for this action as follows. The voluntary consensus standard about reduced mining if NGS were to We estimate a 3.1 percent price ASTM D6348–03 (Reapproved 2010), retire one or more units), and the increase for electricity nationwide in ‘‘Standard Test Method for impacts on employment of tribal 2016 and a less than 2 percent Determination of Gaseous Compounds members at both the NGS and the mine. percentage fall in coal-fired power by Extractive Direct Interface Fourier More specific comments can be found in production as a result of this rule. The Transform (FTIR) Spectroscopy’’ is the docket. EPA projects that electric power sector- acceptable as an alternative to Method The EPA will continue to work with delivered natural gas prices will 320 and is cited in the final rule, but these and other potentially affected increase by about 0.6 percent over the with several conditions: (1) The test tribes as this final rule is implemented. 2015 to 2030 timeframe. For more plan preparation and implementation in information on the estimated energy the Annexes to ASTM D6348–03, G. Executive Order 13045, Protection of effects, please refer to the economic Sections A1 through A8 are mandatory; Children From Environmental Health impact analysis for this final rule. The and (2) In ASTM D6348–03 Annex A5 Risks and Safety Risks analysis is available in the RIA, which (Analyte Spiking Technique), the This final rule is subject to EO 13045 is in the public docket. percent (%) R must be determined for (62 FR 19885; April 23, 1997) because each target analyte (Equation A5.5). In it is an economically significant I. National Technology Transfer and order for the test data to be acceptable regulatory action as defined by EO Advancement Act for a compound, %R must be 70% ≥ R 12866, and EPA believes that the Section 12(d) of the National ≤ 130%. If the %R value does not meet environmental health or safety risk Technology Transfer and Advancement this criterion for a target compound, the addressed by this action may have a Act (NTTAA) of 1995 (Pub. L. 104–113; test data are not acceptable for that disproportionate effect on children. 15 U.S.C. 272 note) directs the EPA to compound and the test must be repeated Accordingly, we have evaluated the use voluntary consensus standards in its for that analyte (i.e., the sampling and/ environmental health or safety effects of regulatory activities unless to do so or analytical procedure should be the standards on children. would be inconsistent with applicable adjusted before a retest). The %R value Although this final rule is based on law or otherwise impractical. Voluntary for each compound must be reported in technology performance, the standards consensus standards are technical the test report, and all field are designed to protect against hazards standards (e.g., materials specifications, measurements must be corrected with to public health with an adequate test methods, sampling procedures, the calculated %R value for that margin of safety as described in Section business practices) that are developed or compound by using the following

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equation: Reported Result = (Measured to make a definitive comparison of the acceptable as an alternative to EPA Concentration in the Stack × 100)/% R. method in these areas. Method 3A. This ISO standard is similar The voluntary consensus standard The voluntary consensus standard to EPA Method 3A, but is missing some ASTM D6784–02, ‘‘Standard Test ISO 10780:1994, ‘‘Stationary Source key features. In terms of sampling, the Method for Elemental, Oxidized, Emissions—Measurement of Velocity hardware required by ISO 12039:2001 Particle-Bound and Total Mercury in and Volume Flowrate of Gas Streams in does not include a 3-way calibration Flue Gas Generated from Coal-Fired Ducts,’’ is impractical as an alternative valve assembly or equivalent to block Stationary Sources (Ontario Hydro to EPA Method 2 in this rule. The the sample gas flow while calibration Method),’’ is an acceptable alternative to standard recommends the use of an L- gases are introduced. In its calibration use of EPA Method 29 for Hg only or shaped pitot, which historically has not procedures, ISO 12039:2001 only Method 30B for the purpose of been recommended by the EPA. The specifies a two-point calibration while conducting relative accuracy tests of Hg EPA specifies the S-type design which EPA Method 3A specifies a three-point continuous monitoring systems under has large openings that are less likely to calibration. Also, ISO 12039:2001 does this final rule. Because of the limitations plug up with dust. not specify performance criteria for of this method in terms of total The voluntary consensus standard, calibration error, calibration drift, or sampling volume, it is not appropriate CAN/CSA Z223.2–M86 (1999), ‘‘Method sampling system bias tests as in the EPA for use in performance testing under for the Continuous Measurement of method, although checks of these this rule. In addition to the voluntary Oxygen, Carbon Dioxide, Carbon quality control features are required by consensus standards the EPA used in Monoxide, Sulphur Dioxide, and Oxides the ISO standard. the final rule, the search for emissions of Nitrogen in Enclosed Combustion The voluntary consensus standard measurement procedures identified 16 Flue Gas Streams,’’ is unacceptable as a ASTM D6522–00, ‘‘Standard Test other voluntary consensus standards. substitute for EPA Method 3A because Method for the Determination of The EPA determined that 14 of these 16 it does not include quantitative Nitrogen Oxides, Carbon Monoxide, and standards identified for measuring specifications for measurement system Oxygen Concentrations in Emissions emissions of the HAP or other performance, most notably the from Natural Gas-Fired Reciprocating pollutants subject to emission standards calibration procedures and instrument Engines, Combustion Turbines, Boilers in the final rule were impractical performance characteristics. The and Process Heaters Using Portable alternatives to EPA test methods for the instrument performance characteristics Analyzers’’ is not an acceptable purposes of this final rule. Therefore, that are provided are non-mandatory alternative to EPA Method 3A for the EPA did not adopt these standards and also do not provide the same level measuring CO and O2 concentrations for for this purpose. The reasons for this of quality assurance as the EPA this final rule as the method is designed determination for the 14 methods are methods. For example, the zero and for application to sources firing natural discussed below, and the remaining 2 span/calibration drift is only checked gas. methods are discussed later in this weekly, whereas the EPA methods The voluntary consensus standard section. require drift checks after each run. ASME PTC–38–80 R85 (1985), The voluntary consensus standard Two very similar voluntary consensus ‘‘Determination of the Concentration of ASTM D3154–00, ‘‘Standard Method for standards, ASTM D5835–95 Particulate Matter in Gas Streams,’’ is Average Velocity in a Duct (Pitot Tube (Reapproved 2001), ‘‘Standard Practice not acceptable as an alternative for EPA Method),’’ is impractical as an for Sampling Stationary Source Method 5 because ASTM PTC–38–80 is alternative to EPA Methods 1, 2, 3B, and Emissions for Automated Determination not specific about equipment 4 for the purposes of this rulemaking of Gas Concentration,’’ and ISO requirements, and instead presents the because the standard appears to lack in 10396:1993, ‘‘Stationary Source options available and the pros and cons quality control and quality assurance Emissions: Sampling for the Automated of each option. The key specific requirements. Specifically, ASTM Determination of Gas Concentrations,’’ differences between ASME PTC–38–80 D3154–00 does not include the are impractical alternatives to EPA and the EPA methods are that the ASME following: (1) proof that openings of Method 3A for the purposes of this final standard: (1) Allows in-stack filter standard pitot tube have not plugged rule because they lack in detail and placement as compared to the out-of- during the test; (2) if differential quality assurance/quality control stack filter placement in EPA Methods pressure gauges other than inclined requirements. Specifically, these two 5 and 17; (2) allows many different manometers (e.g., magnehelic gauges) standards do not include the following: types of nozzles, pitots, and filtering are used, their calibration must be (1) Sensitivity of the method; (2) equipment; (3) does not specify a filter checked after each test series; and (3) acceptable levels of analyzer calibration weighing protocol or a minimum the frequency and validity range for error; (3) acceptable levels of sampling allowable filter weight fluctuation as in calibration of the temperature sensors. system bias; (4) zero drift and the EPA methods; and (4) allows filter The voluntary consensus standard calibration drift limits, time span, and paper to be only 99 percent efficient, as ASTM D3464–96 (Reapproved 2001), required testing frequency; (5) a method compared to the 99.95 percent ‘‘Standard Test Method Average to test the interference response of the efficiency required by the EPA methods. Velocity in a Duct Using a Thermal analyzer; (6) procedures to determine The voluntary consensus standard Anemometer,’’ is impractical as an the minimum sampling time per run ASTM D3685/D3685M–98, ‘‘Test alternative to EPA Method 2 for the and minimum measurement time; and Methods for Sampling and purposes of this rule primarily because (7) specifications for data recorders, in Determination of Particulate Matter in applicability specifications are not terms of resolution (all types) and Stack Gases,’’ is similar to EPA Methods clearly defined, e.g., range of gas recording intervals (digital and analog 5 and 17, but is lacking in the following composition, temperature limits. Also, recorders, only). areas that are needed to produce quality, the lack of supporting quality assurance The voluntary consensus standard representative particulate data: (1) data for the calibration procedures and ISO 12039:2001, ‘‘Stationary Source Requirement that the filter holder specifications, and certain variability Emissions—Determination of Carbon temperature should be between 120°C issues that are not adequately addressed Monoxide, Carbon Dioxide, and and 134°C, and not just ‘‘above the acid by the standard limit the EPA’s ability Oxygen—Automated Methods,’’ is not dew-point’’; (2) detailed specifications

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for measuring and monitoring the filter weighing every 6 hours until a constant Measurement by Velocity Traverse,’’ for holder temperature during sampling; (3) weight is achieved. Third, EPA Method EPA Method 2 (and possibly 1); and procedures similar to EPA Methods 1, 2, 5 requires the filter weight to be ASME/BSR MFC 12M, ‘‘Flow in Closed 3, and 4, that are required by EPA reported to the nearest 0.1 milligram Conduits Using Multiport Averaging Method 5; (4) technical guidance for (mg), while CAN/CSA Z223.1 requires Pitot Primary Flowmeters,’’ for EPA performing the Method 5 sampling reporting only to the nearest 0.5 mg. Method 2. procedures, e.g., maintaining and Also, CAN/CSA Z223.1 allows the use Finally, in addition to the three monitoring sampling train operating of a standard pitot for velocity voluntary consensus standards temperatures, specific leak check measurement when plugging of the tube identified as acceptable alternatives to guidelines and procedures, and use of opening is not expected to be a problem. EPA methods required in the final rule, reagent blanks for determining and The EPA Method 5 requires an S-shaped the EPA is also specifying four subtracting background contamination; pitot. voluntary consensus standards in the and (5) detailed equipment and/or The voluntary consensus standard EN rule for use in sampling and analysis of operational requirements, e.g., 1911–1,2,3 (1998), ‘‘Stationary Source liquid oil samples for moisture content. component exchange leak checks, use of Emissions-Manual Method of These standards are: ASTM D95–05 glass cyclones for heavy particulate Determination of HCl-Part 1: Sampling (Reapproved 2010), ‘‘Standard Test loading and/or water droplets, operating of Gases Ratified European Text-Part 2: Method for Water in Petroleum Products under a negative stack pressure, Gaseous Compounds Absorption and Bituminous Materials by exchanging particulate loaded filters, Ratified European Text-Part 3: Distillation,’’ ASTM D4006–11, sampling preparation and Adsorption Solutions Analysis and ‘‘Standard Test Method for Water in implementation guidance, sample Calculation Ratified European Text,’’ is Crude Oil by Distillation,’’ ASTM recovery guidance, data reduction impractical as an alternative to EPA D4177–95 (Reapproved 2010), guidance, and particulate sample Methods 26 and 26A. Part 3 of this ‘‘Standard Practice for Automatic calculations input. standard cannot be considered Sampling of Petroleum and Petroleum The voluntary consensus standard equivalent to EPA Method 26 or 26A Products,’’ and ASTM D4057–06 ISO 9096:1992, ‘‘Determination of because the sample absorbing solution (Reapproved 2011), ‘‘Standard Practice Concentration and Mass Flow Rate of (water) would be expected to capture for Manual Sampling of Petroleum and Particulate Matter in Gas Carrying both HCl and chlorine gas, if present, Petroleum Products.’’ Ducts—Manual Gravimetric Method,’’ is without the ability to distinguish Table 5, section 4.1.1.5 of appendix A, not acceptable as an alternative for EPA between the two. The EPA Methods 26 and section 3.1.2 of appendix B to Method 5. Although sections of ISO and 26A use an acidified absorbing subpart UUUUU, 40 CFR part 63, list 9096 incorporate EPA Methods 1, 2, and solution to first separate HCl and the EPA testing methods included in the 5 to some degree, this ISO standard is chlorine gas so that they can be final rule. Under section 63.7(f) and not equivalent to EPA Method 5 for selectively absorbed, analyzed, and section 63.8(f) of subpart A of the collection of PM. The standard ISO 9096 reported separately. In addition, in EN General Provisions, a source may apply does not provide applicable technical 1911 the absorption efficiency for to the EPA for permission to use guidance for performing many of the chlorine gas would be expected to vary alternative test methods or alternative integral procedures specified in as the pH of the water changed during monitoring requirements in place of any Methods 1, 2, and 5. Major performance sampling. of the EPA testing methods, and operational details are lacking or The voluntary consensus standard EN performance specifications, or nonexistent, and detailed quality 13211 (1998), is not acceptable as an procedures specified. alternative to the Hg portion of EPA assurance/quality control guidance for J. Executive Order 12898: Federal Method 29 primarily because it is not the sampling operations required to Actions To Address Environmental produce quality, representative validated for use with impingers, as in Justice in Minority Populations and particulate data (e.g., guidance for the EPA method, although the method Low-Income Populations maintaining and monitoring train describes procedures for the use of operating temperatures, specific leak impingers. This European standard is Executive Order 12898 (59 FR 7629; check guidelines and procedures, and validated for the use of fritted bubblers February 16, 1994) establishes federal sample preparation and recovery only and requires the use of a side executive policy on environmental procedures) are not provided by the (split) stream arrangement for isokinetic justice (EJ). Its main provision directs standard, as in EPA Method 5. Also, sampling because of the low sampling federal agencies, to the greatest extent details of equipment and/or operational rate of the bubblers (up to 3 liters per practicable and permitted by law, to requirements, such as those specified in minute, maximum). Also, only two make EJ part of their mission by EPA Method 5, are not included in the bubblers (or impingers) are required by identifying and addressing, as ISO standard, e.g., stack gas moisture EN 13211, whereas EPA Method 29 appropriate, disproportionately high measurements, data reduction guidance, require the use of six impingers. In and adverse human health or and particulate sample calculations. addition, EN 13211 does not include environmental effects of their programs, The voluntary consensus standard many of the quality control procedures policies, and activities on minority CAN/CSA Z223.1–M1977, ‘‘Method for of EPA Method 29, especially for the use populations and low-income the Determination of Particulate Mass and calibration of temperature sensors populations in the U.S. Flows in Enclosed Gas Streams,’’ is not and controllers, sampling train assembly The EPA has determined that this acceptable as an alternative for EPA and disassembly, and filter weighing. final rule will not have Method 5. Detailed technical procedures Two of the 16 voluntary consensus disproportionately high and adverse and quality control measures that are standards identified in this search were human health or environmental effects required in EPA Methods 1, 2, 3, and 4 not available at the time the review was on minority, low income, and are not included in CAN/CSA Z223.1. conducted for the purposes of the final indigenous populations because it Second, CAN/CSA Z223.1 does not rule because they are under increases the level of environmental include the EPA Method 5 filter development by a voluntary consensus protection for all affected populations weighing requirement to repeat body: ASME/BSR MFC 13M, ‘‘Flow without having any disproportionately

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high and adverse human health or industry and on communities currently benefits of reducing exposure to Hg and environmental effects on any breathing dirty air. Therefore, we the other HAP. population, including any minority, low anticipate significant interest in many, if The EPA’s full analysis of risks from income, and indigenous populations. not most, of these actions from EJ consumption of Hg-contaminated fish is This final rule establishes national communities, among many others. contained in the RIA for this rule. The emission standards for new and existing effects of this final rule on the health EGUs that combust coal and oil. The 1. Key EJ Aspects of the Rule risks from Hg and other HAP are EPA estimates that there are This is an air toxics rule; therefore, it presented in the preamble and in the approximately 1,400 units located at does not permit emissions trading RIA for this rule. 600 facilities covered by this final rule. among sources. Instead, this final rule 2. Potential Environmental and Public This final rule will reduce emissions will place a limit on the rates of Hg and of all the listed HAP that come from Health Impacts to Minority, Low other HAP emitted from each affected Income, or Tribal Populations EGUs. This includes metals (Hg, As, Be, EGU. As a result, emissions of Hg and Cd, Cr, Pb, Mn, Ni, and Se), organics other HAP such as HCl will be The EPA has conducted several (POM, acetaldehyde, acrolein, benzene, substantially reduced in the vast analyses that provide additional insight dioxins, ethylene dichloride, majority of states. In some states, on the potential effects of this rule on formaldehyde, and PCB), and acid gases however, there may be small increases EJ communities. These include: (1) The (HCl and HF). At sufficient levels of in Hg and other HAP emissions due to socio-economic distribution of people exposure, these pollutants can cause a shifts in electricity generation from living close to affected EGUs who may range of health effects including cancer; EGUs with higher emission rates to be exposed to pollution from these irritation of the lungs, skin, and mucous EGUs with already low emission rates. sources; and (2) an analysis of the membranes; effects on the central Hydrogen chloride emissions are distribution of health effects expected nervous system such as memory and IQ projected to increase at a small number from the reductions in PM2.5 that will loss and learning disabilities; damage to of sources but that does not lead to any result from implementation of this final the kidneys; and other acute health increased emissions at the state level. rule (co-benefits). disorders. a. Socio-Economic Distribution. As The final rule will also result in The primary risk analysis to support part of the analysis for this final rule, substantial reductions of criteria the finding that this final rule is both the EPA reviewed the aggregate appropriate and necessary includes an pollutants such as CO, PM, and SO2. demographic makeup of the Sulfur dioxide is a precursor pollutant analysis of the effects of Hg from EGUs communities near EGUs covered by this that is often transformed into fine PM on people who rely on freshwater fish final rule. Although this analysis gives they catch as a regular and frequent part (PM2.5) in the atmosphere. Reducing some indication of populations that may of their diet. These groups are direct emissions of PM2.5 and SO2 will, be exposed to levels of pollution that as a result, reduce concentrations of characterized as subsistence level cause concern, it does not identify the fishing populations or fishers. A PM2.5 in the atmosphere. These demographic characteristics of the most significant portion of the data in this reductions in PM2.5 will provide large highly affected individuals or health benefits, such as reducing the analysis came from published studies of communities. Electric generating units risk of premature mortality for adults, EJ communities where people usually have very tall emission stacks; chronic and acute bronchitis, childhood frequently consume locally-caught this tends to disperse the pollutants asthma attacks, and hospitalizations for freshwater fish. These communities emitted from these stacks fairly far from other respiratory and cardiovascular included: (1) White and black the source. In addition, several of the diseases. (For more details on the health populations (including female and poor pollutants emitted by these sources, strata) surveyed in South Carolina; (2) effects of metals, organics, and PM2.5, such as a common form of Hg and SO2, please refer to the RIA contained in the Hispanic, Vietnamese and Laotian are known to travel long distances and docket for this rulemaking.) This final populations surveyed in California; and contribute to adverse impacts on both rule will also have a small effect on (3) Great Lakes tribal populations the environment and human health electricity and natural gas prices but has (Chippewa and Ojibwe) active on ceded hundreds or even thousands of miles the potential to affect the cost structure territories around the Great Lakes. These from where they were emitted (in the of the utility industry and could lead to data were used to help estimate risks to case of elemental Hg, globally). shifts in how and where electricity is similar populations beyond the areas The proximity-to-the-source review is generated. where the study data were collected. For included in the analysis for this final This final rule is one of a group of example, while the Vietnamese and rule because some EGUs emit enough regulatory actions that the EPA has Laotian survey data were collected in HAP such as Ni or Cr(VI) to cause taken and will take over the next several California, given the ethnic (heritage) elevated lifetime cancer risks greater years to respond to statutory and nature of these high fish consumption than 1 in a million in nearby judicial mandates that will reduce rates, we assumed that they could also communities. In addition, the EPA’s exposure to HAP and PM2.5, as well as be associated with members of these analysis indicates that there are to other pollutants, from EGUs and ethnic groups living elsewhere in the localized areas with potential for other sources. In addition, the EPA will U.S. Therefore, the high-end elevated levels of Hg deposition around pursue energy efficiency improvements consumption rates referenced in the most U.S. EGUs.381 throughout the economy, along with California study for these ethnic groups The analysis of demographic data other federal agencies, states and other were used to model risk at watersheds used proximity-to-the-source as a groups. This will contribute to elsewhere in the U.S. As a result of this surrogate for exposure to identify those additional environmental and public approach, the specific fish consumption populations considered to be living near health improvements while lowering patterns of several different EJ groups affected sources, such that they have the costs of realizing those are fundamental to the EPA’s notable exposures to current HAP improvements. Together, these rules assessment of both the underlying risks and actions will have substantial and that make this final rule appropriate and 381 See Excess Local Deposition TSD for more long-term effects on both the U.S. power necessary, and of the analysis of the detail.

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emissions from these sources. The In determining the aggregate sources (assuming there are other demographic data for this analysis were demographic makeup of the sources in the area, as is typical in extracted from the 2000 census data communities near affected sources, the urban areas). Although facility processes which were provided to the EPA by the EPA focused on those census blocks and fugitive emissions may have more U.S. Census Bureau. Distributions by within three miles of affected sources localized impacts, the EPA race are based on demographic and determined the demographic acknowledges that because of various information at the census block level, composition (e.g., race, income, etc.) of stack heights there is the potential for and all other demographic groups are these census blocks and compared them dispersion beyond 3 miles. To the based on the extrapolation of census to the corresponding compositions extent that any minority, low income, block group level data to the census nationally. The radius of 3 miles (or and indigenous subpopulation is block level. The socio-demographic approximately 5 kilometers) is disproportionately impacted by the parameters used in the analysis consistent with other demographic included the following categories: analyses focused on areas around current emissions as a result of the Racial (White, African American, Native potential sources. In addition, air proximity of their homes to these American, Other or Multiracial, and All quality modeling experience has shown sources, that subpopulation also stands Other Races); Ethnicity (Hispanic); and that the area within three miles of an to see increased environmental and Other (Number of people below the individual source of emissions can health benefit from the emissions poverty line, Number of people with generally be considered the area with reductions called for by this rule. The ages between 0 and 18, Number of the highest ambient air levels of the results of the EPA’s demographic people greater than or equal to 65, primary pollutants being emitted for analysis for affected sources are shown Number of people with no high school most sources, both in absolute terms in the following table: 382 383 diploma). and relative to the contribution of other

TABLE 12—COMPARATIVE SUMMARY OF THE DEMOGRAPHICS WITHIN 5 KM (3 MILES) OF THE AFFECTED SOURCES [Population in millions] 382

African Native Other and multi- 383 Below poverty White American American racial Hispanic Minority line

Near Source Total (3 mi) 8 .78 2.51 0.10 2 .52 2.86 5 .13 2.43 % of Near Source Total 63 18 1 18 21 37 17 National Total 215 35 2 .49 33.3 39 .1 70 .8 37 .1 % of National Total ...... 75 12 1 12 14 25 13 382 Racial and ethnic categories overlap and cannot be summed. 383 The ‘‘Minority’’ population is the overall population (in the first row) minus white population (in the second row).

The data indicate that coal-fired EGUs elderly, and people with existing heart 11,000 fewer premature mortalities, are located in areas where the minority and lung diseases, including asthma. 2,900 fewer cases of chronic bronchitis, share of the population living within a Exposure can cause premature death 4,800 fewer non-fatal heart attacks, three mile buffer is higher than the and trigger heart attacks, asthma attacks 2,600 fewer hospitalizations (for national average by 12 percentage points in children and adults with asthma, respiratory and cardiovascular disease or 48 percent. For these same areas, the chronic and acute bronchitis, and combined), 3.2 million fewer days of percent of the population below the emergency room visits and restricted activity due to respiratory poverty line is also higher than the hospitalizations, as well as milder illness and approximately 540,000 fewer national average by 4 percentage points illnesses that keep children home from lost work days. As described in EO or 31 percent. These results are school and adults home from work. 13045, Protection of Children from presented in more detail in the ‘‘Review Missing work due to illness or the Environmental Health Risks and Safety of Proximity Analysis,’’ February 2011, illness of a child is a particular problem Risks, we also estimate substantial a copy of which is available in the for people who have jobs that do not health improvements for children. docket. provide paid sick days. Low-wage We also examined the PM2.5 mortality employees also risk losing their jobs if b. PM2.5 (Co-Benefits) Analysis. As risks according to race, income, and mentioned above, many of the steps they are absent too often, even if it is educational attainment. We then EGUs will take to reduce their emissions due to their own illness or the illness of estimated the change in PM2.5 mortality of air toxics as required by this final rule a child or other relative. Finally, many risk as a result of this final rule among will also reduce emissions of PM and individuals in these communities lack people living in the counties with the access to high quality health care to SO2. As a result, this final rule will highest (top 5 percent) PM2.5 mortality treat these types of illnesses. Due to all reduce concentrations of PM2.5 in the risk in 2005. We then compared the these factors, many minority and low- atmosphere. Exposure to PM2.5 can change in risk among the people living cause or contribute to adverse health income communities are particularly in these ‘‘high-risk’’ counties with effects, such as asthma and heart susceptible to the health effects of PM2.5 people living in all other counties. disease, that significantly affect many and receive a variety of benefits from In 2005, people living in the highest minority, low-income, and tribal reducing it. risk counties and in the poorest counties individuals and their communities. Fine We estimate that in 2016 the annual had a substantially higher risk of PM2.5- PM (PM2.5) is particularly (but not PM-related benefits of the final rule for related death than people living in the exclusively) harmful to children, the adults include approximately 4,200 to other 95 percent of counties. This was

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true regardless of race; the difference yosemite.epa.gov/opei/RuleGate.nsf/). indigenous populations. The EPA is between the groups of counties for each During the comment period, the EPA providing multiple opportunities for EJ race was large while the differences discussed the proposed rule via a communities to both learn about and among races in both groups of counties conference call with communities, comment on this rule and welcomes was very small. In contrast, the analysis conducted a community-oriented their participation as implementation of found that people with less than high webinar on the proposed rule, and the rule proceeds. school education had a significantly posted the webinar presentation on- K. Congressional Review Act greater risk from PM2.5 mortality than line. The EPA also held three public people with a greater than high school hearings to receive additional input on The Congressional Review Act, 5 education. This was true both for the the proposal. U.S.C. 801 et seq., as added by the Small highest-risk counties and for the other There will continue to be Business Regulatory Enforcement counties. In summary, the analysis opportunities for public notice and Fairness Act of 1996, generally provides indicates that in 2005, educational comment as the utilities move forward that before a rule may take effect, the status, living in one of the poorest with implementation of this rule. Once agency promulgating the rule must counties, and living in a high-risk the rule is finalized, affected EGUs will submit a rule report, which includes a county are associated with higher PM2.5 need to update their Title V operating copy of the rule, to each House of the mortality risk while race is not. permits to reflect their new emission Congress and to the Comptroller General Our analysis demonstrates that this limits, any other new applicable of the U.S. The EPA will submit a report final rule will significantly reduce the requirements, and the associated containing this rule and other required PM2.5 mortality among all populations monitoring and recordkeeping from this information to the U.S. Senate, the U.S. of different races living throughout the rule. The Title V permitting process House of Representatives, and the U.S. compared to both 2005 and 2016 provides that when most permits are Comptroller General of the U.S. prior to pre-rule (i.e., base case) levels. The reopened (for example, to incorporate publication of the rule in the Federal analysis indicates that people living in new applicable requirements) or Register. A major rule cannot take effect counties with the highest rates (top 5 renewed, there must be opportunity for until 60 days after it is published in the percent) of PM2.5 mortality risk in 2005 public review and comments. In Federal Register. This action is a ‘‘major receive the largest reduction in addition, after the public review rule’’ as defined by 5 U.S.C. 804(2). This mortality risk after this rule takes effect. process, the EPA has an opportunity to rule will be effective April 16, 2012. We also find that people living in the review the proposed permit and object poorest 5 percent of the counties receive to its issuance if it does not meet CAA List of Subjects a larger reduction in PM mortality risk 2.5 requirements. 40 CFR Part 60 than all other counties. More 4. Additional Analysis information can be found in Section Environmental protection, 7.11 of the RIA. In addition to the previously Administrative practice and procedure, The EPA estimates that the benefits of described assessment of EJ impacts, the Air pollution control, Incorporation by the final rule are distributed among EPA conducted an analysis of sub- reference, Intergovernmental relations, races, income levels, and levels of populations with particularly high Reporting and recordkeeping education fairly evenly. However, the potential risks of Hg exposure due to requirements. analysis does indicate that this final rule high rates of fish consumption. These in conjunction with the implementation populations overlap in many cases with 40 CFR Part 63 of existing or final rules (e.g., the traditional EJ populations and would Environmental protection, CSAPR) will reduce the disparity in risk benefit from Hg reductions resulting Administrative practice and procedure, between those in the highest-risk from this rule. The EPA also conducted Air pollution control, Hazardous counties and the other 95 percent of an analysis of the distribution of PM2.5- substances, Incorporation by reference, counties for all races and educational related mortality risk according to the Intergovernmental relations, Reporting levels. In addition, in many cases race, income and education of the and recordkeeping requirements. implementation of this final rule and population and how MATS changes this other rules will, together, reduce risks in distribution. These analyses can be Dated: December 16, 2011. the highest-risk counties to the found in Section 7.12 of the RIA. Lisa P. Jackson, approximate level of risk for the rest of Administrator. 5. Summary the counties as it existed before implementation of the rule. This final rule strictly limits the For the reasons stated in the These results are presented in more emissions rate of Hg and other HAP preamble, title 40, chapter I, of the Code detail in Section 7.11 of the RIA. from every affected EGU. The EPA’s of the Federal Regulations is amended analysis indicates substantial health as follows: 3. Meaningful Public Participation benefits, including for minority, low The EPA defines ‘‘environmental income, and indigenous populations, PART 60—[AMENDED] justice’’ to include meaningful from reductions in PM2.5. involvement of all people regardless of The EPA’s analysis also indicates ■ 1. The authority citation for part 60 race, color, national origin, or income reductions in risks for individuals, continues to read as follows: with respect to the development, including for members of minority Authority: 42 U.S.C. 7401 et seq. implementation, and enforcement of populations, who eat fish frequently environmental laws, regulations, and from U.S. lakes and rivers and who live Subpart A—[Amended] policies. To promote meaningful near affected sources. Based on all the involvement, the EPA publicized the available information, the EPA has ■ 2. Section 60.17 is amended: rulemaking via newsletters, EJ determined that this final rule will not ■ a. By redesignating paragraph (a)(93), listserves, and the internet, including have disproportionately high and added March 21, 2011, at 76 FR 15750, the Office of Policy’s (OP) Rulemaking adverse human health or environmental and delayed indefinitely at 76 FR 28664, Gateway Web site (http:// effects on minority, low income, and May 18, 2011, as paragraph (a)(96);

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■ b. By redesignating paragraphs (a)(91) ■ 4. Section 60.24 is amended as ■ 8. Section 60.42 is amended as and (a)(92) as paragraphs (a)(94) and follows: follows: (a)(95); ■ a. By revising paragraph (b)(1). ■ a. By revising paragraph (a) ■ c. By redesignating paragraphs (a)(89) ■ b. By removing paragraph (h). introductory text. and (a)(90) as paragraphs (a)(91) and ■ b. By adding paragraph (d). (a)(92); § 60.24 Emission standards and ■ c. By adding paragraph (e). compliance schedules. ■ d. By redesignating paragraphs (a)(54) * * * * * § 60.42 Standard for particulate matter through (a)(88) as paragraphs (a)(55) (PM). through (a)(89); (b) * * * (a) Except as provided under ■ e. By adding paragraph (a)(54); (1) Emission standards shall either be paragraphs (b), (c), (d), and (e) of this ■ f. By adding paragraph (a)(90); and based on an allowance system or section, on and after the date on which ■ g. By adding paragraph (a)(93) to read prescribe allowable rates of emissions the performance test required to be as follows: except when it is clearly impracticable. Such cases will be identified in the conducted by § 60.8 is completed, no § 60.17 Incorporations by reference. guideline documents issued under owner or operator subject to the * * * * * § 60.22. Where emission standards provisions of this subpart shall cause to (a) * * * prescribing equipment specifications are be discharged into the atmosphere from (54) ASTM D3699–08, Standard established, the plan shall, to the degree any affected facility any gases that: Specification for Kerosine, including possible, set forth the emission * * * * * Appendix X1, approved September 1, reductions achievable by (d) An owner or operator of an 2008, IBR approved for §§ 60.41b of implementation of such specifications, affected facility that combusts only subpart Db of this part and 60.41c of and may permit compliance by the use natural gas is exempt from the PM and subpart Dc of this part. of equipment determined by the State to opacity standards specified in paragraph * * * * * be equivalent to that prescribed. (a) of this section. (90) ASTM D6751–11b, Standard * * * * * (e) An owner or operator of an Specification for Biodiesel Fuel Blend affected facility that combusts only Stock (B100) for Middle Distillate Fuels, Subpart D—[Amended] gaseous or liquid fossil fuel (excluding including Appendices X1 through X3, residual oil) with potential SO2 ■ approved July 15, 2011, IBR approved 5. The subpart heading for Subpart D emissions rates of 26 ng/J (0.060 lb/ for §§ 60.41b of subpart Db of this part is revised to read as follows: MMBtu) or less and that does not use and 60.41c of subpart Dc of this part. post-combustion technology to reduce Subpart D—Standards of Performance emissions of SO2 or PM is exempt from * * * * * for Fossil-Fuel-Fired Steam Generators the PM standards specified in paragraph (93) ASTM D7467–10, Standard (a) of this section. Specification for Diesel Fuel Oil, ■ 6. Section 60.40 is amended by ■ Biodiesel Blend (B6 to B20), including revising paragraph (e) to read as follows: 9. Section 60.45 is amended as follows: Appendices X1 through X3, approved ■ August 1, 2010, IBR approved for § 60.40 Applicability and designation of a. By revising paragraph (a). affected facility. ■ b. By revising paragraph (b) §§ 60.41b of subpart Db of this part and introductory text. 60.41c of subpart Dc of this part. * * * * * ■ c. By revising paragraphs (b)(1) * * * * * (e) Any facility subject to either subpart Da or KKKK of this part is not through (5). ■ d. By revising paragraph (b)(6) Subpart B—[Amended] subject to this subpart. ■ introductory text. 7. Section 60.41 is amended by adding ■ ■ 3. Section 60.21 is amended as e. By revising paragraphs (b)(7)(i)(A) the definition of ‘‘natural gas’’ in through (C). follows: alphabetical order to read as follows: ■ ■ a. By revising paragraph (a). f. By revising paragraph (b)(7)(ii)(B). ■ g. By adding paragraph (b)(8). ■ b. By revising paragraph (f). § 60.41 Definitions. ■ c. By removing paragraph (k). * * * * * § 60.45 Emissions and fuel monitoring. Natural gas means a fluid mixture of § 60.21 Definitions. (a) Each owner or operator of an hydrocarbons (e.g., methane, ethane, or affected facility subject to the applicable * * * * * propane), composed of at least 70 emissions standard shall install, (a) Designated pollutant means any percent methane by volume or that has calibrate, maintain, and operate air pollutant, the emissions of which are a gross calorific value between 35 and continuous opacity monitoring system subject to a standard of performance for 41 megajoules (MJ) per dry standard (COMS) for measuring opacity and a new stationary sources, but for which cubic meter (950 and 1,100 Btu per dry continuous emissions monitoring air quality criteria have not been issued standard cubic foot), that maintains a system (CEMS) for measuring SO and that is not included on a list 2 gaseous state under ISO conditions. In emissions, NO emissions, and either published under section 108(a) or X addition, natural gas contains 20.0 oxygen (O ) or carbon dioxide (CO ) section 112(b)(1)(A) of the Act. 2 2 grains or less of total sulfur per 100 except as provided in paragraph (b) of * * * * * standard cubic feet. Finally, natural gas this section. (f) Emission standard means a legally does not include the following gaseous (b) Certain of the CEMS and COMS enforceable regulation setting forth an fuels: landfill gas, digester gas, refinery requirements under paragraph (a) of this allowable rate of emissions into the gas, sour gas, blast furnace gas, coal- section do not apply to owners or atmosphere, establishing an allowance derived gas, producer gas, coke oven operators under the following system, or prescribing equipment gas, or any gaseous fuel produced in a conditions: specifications for control of air pollution process which might result in highly (1) For a fossil-fuel-fired steam emissions. variable sulfur content or heating value. generator that combusts only gaseous or * * * * * * * * * * liquid fossil fuel (excluding residual oil)

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with potential SO2 emissions rates of 26 specified in paragraphs (b)(6)(i) through Subpart Da—Standards of ng/J (0.060 lb/MMBtu) or less and that (iv) of this section. Performance for Electric Utility Steam does not use post-combustion * * * * * Generating Units technology to reduce emissions of SO2 or PM, COMS for measuring the opacity (7) * * * ■ 11. Section 60.40Da is amended by of emissions and CEMS for measuring (i) * * * revising paragraphs (b)(1) and (e) to read as follows: SO2 emissions are not required if the (A) If no visible emissions are owner or operator monitors SO 2 observed, a subsequent Method 9 of § 60.40Da Applicability and designation of emissions by fuel sampling and analysis appendix A–4 of this part performance affected facility. or fuel receipts. (2) For a fossil-fuel-fired steam test must be completed within 12 * * * * * generator that does not use a flue gas calendar months from the date that the (b) * * * (1) The IGCC electric utility steam desulfurization device, a CEMS for most recent performance test was measuring SO emissions is not required conducted or within 45 days of the next generating unit is capable of combusting 2 more than 73 MW (250 MMBtu/h) heat if the owner or operator monitors SO2 day that fuel with an opacity standard emissions by fuel sampling and is combusted, whichever is later; input of fossil fuel (either alone or in combination with any other fuel) in the analysis. (B) If visible emissions are observed (3) Notwithstanding § 60.13(b), combustion turbine engine and but the maximum 6-minute average associated heat recovery steam installation of a CEMS for NOX may be opacity is less than or equal to 5 generator; and delayed until after the initial percent, a subsequent Method 9 of * * * * * performance tests under § 60.8 have appendix A–4 of this part performance been conducted. If the owner or (e) Applicability of this subpart to an test must be completed within 6 operator demonstrates during the electric utility combined cycle gas calendar months from the date that the performance test that emissions of NOX turbine other than an IGCC electric are less than 70 percent of the most recent performance test was utility steam generating unit is as applicable standards in § 60.44, a CEMS conducted or within 45 days of the next specified in paragraphs (e)(1) through day that fuel with an opacity standard for measuring NOX emissions is not (3) of this section. required. If the initial performance test is combusted, whichever is later; (1) Affected facilities (i.e. heat results show that NOX emissions are (C) If the maximum 6-minute average recovery steam generators used with greater than 70 percent of the applicable opacity is greater than 5 percent but less duct burners) associated with a standard, the owner or operator shall than or equal to 10 percent, a stationary combustion turbine that are install a CEMS for NOX within one year subsequent Method 9 of appendix A–4 capable of combusting more than 73 after the date of the initial performance of this part performance test must be MW (250 MMBtu/h) heat input of fossil tests under § 60.8 and comply with all completed within 3 calendar months fuel are subject to this subpart except in cases when the affected facility (i.e. heat other applicable monitoring from the date that the most recent recovery steam generator) meets the requirements under this part. performance test was conducted or (4) If an owner or operator is not applicability requirements of and is within 45 days of the next day that fuel required to and elects not to install any subject to subpart KKKK of this part. with an opacity standard is combusted, CEMS for either SO2 or NOX, a CEMS (2) For heat recovery steam generators whichever is later; or for measuring either O2 or CO2 is not use with duct burners subject to this required. * * * * * subpart, only emissions resulting from (5) For affected facilities using a PM (ii) * * * the combustion of fuels in the steam CEMS, a bag leak detection system to generating unit (i.e. duct burners) are monitor the performance of a fabric (B) If no visible emissions are subject to the standards under this filter (baghouse) according to the most observed for 10 operating days during subpart. (The emissions resulting from current requirements in § 60.48Da of which an opacity standard is applicable, the combustion of fuels in the stationary this part, or an ESP predictive model to observations can be reduced to once combustion turbine engine are subject to monitor the performance of the ESP every 7 operating days during which an subpart GG or KKKK, as applicable, of developed in accordance and operated opacity standard is applicable. If any this part.) according to the most current visible emissions are observed, daily (3) Any affected facility that meets the requirements in section § 60.48Da of observations shall be resumed. applicability requirements and is this part a COMS is not required. * * * * * subject to subpart Eb or subpart CCCC (6) A COMS for measuring the opacity of this part is not subject to the emission of emissions is not required for an (8) A COMS for measuring the opacity standards under subpart Da. of emissions is not required for an affected facility that does not use post- ■ 12. Section 60.41Da is amended as combustion technology (except a wet affected facility at which the owner or follows: scrubber) for reducing PM, SO2, or operator installs, calibrates, operates, ■ a. By revising the definitions of carbon monoxide (CO) emissions, burns and maintains a particulate matter ‘‘boiler operating day’’, ‘‘gaseous fuel’’, only gaseous fuels or fuel oils that continuous parametric monitoring ‘‘integrated gasification combined cycle contain less than or equal to 0.30 weight system (PM CPMS) according to the electric utility steam generating unit’’, percent sulfur, and is operated such that requirements specified in subpart ‘‘natural gas’’, ‘‘petroleum’’, ‘‘potential emissions of CO to the atmosphere from UUUUU of part 63. combustion concentration’’, and ‘‘steam the affected source are maintained at * * * * * generating unit’’. levels less than or equal to 0.15 lb/ ■ b. By adding the definitions of MMBtu on a boiler operating day Subpart Da—[Amended] ‘‘affirmative defense’’, ‘‘combined heat average basis. Owners and operators of and power’’, ‘‘gross energy output’’, ‘‘net affected sources electing to comply with ■ 10. The subpart heading for Subpart energy output’’, ‘‘out-of-control period’’, this paragraph must demonstrate Da is revised to read as follows: and ‘‘petroleum coke’’ in alphabetical compliance according to the procedures order.

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■ c. By removing the definitions of 2011, the gross electrical or mechanical repair. No solid fuel is directly burned ‘‘available purchase power’’, output from the affected facility minus in the unit during operation. ‘‘cogeneration’’, ‘‘dry flue gas any electricity used to power the * * * * * desulfurization technology ‘‘, ‘‘electric feedwater pumps and any associated gas Natural gas means a fluid mixture of utility company’’, ‘‘emergency compressors (air separation unit main hydrocarbons (e.g., methane, ethane, or condition’’, ‘‘emission rate period’’, compressor, oxygen compressor, and propane), composed of at least 70 ‘‘gross output’’, ‘‘interconnected’’, ‘‘net nitrogen compressor) plus 75 percent of percent methane by volume or that has system capacity’’, ‘‘principal company’’, the useful thermal output measured a gross calorific value between 35 and ‘‘responsible official’’, ‘‘spare flue gas relative to ISO conditions that is not 41 megajoules (MJ) per dry standard desulfurization system module’’, used to generate additional electrical or cubic meter (950 and 1,100 Btu per dry ‘‘spinning reserve’’, ‘‘system emergency mechanical output or to enhance the standard cubic foot), that maintains a reserves’’, and ‘‘system load’’. performance of the unit (i.e., steam gaseous state under ISO conditions. In delivered to an industrial process); § 60.41Da Definitions. addition, natural gas contains 20.0 (3) For combined heat and power grains or less of total sulfur per 100 * * * * * facilities constructed, reconstructed, or standard cubic feet. Finally, natural gas Affirmative defense means, in the does not include the following gaseous context of an enforcement proceeding, a modified after May 3, 2011, the gross electrical or mechanical output from the fuels: landfill gas, digester gas, refinery response or defense put forward by a gas, sour gas, blast furnace gas, coal- defendant, regarding which the affected facility divided by 0.95 minus any electricity used to power the derived gas, producer gas, coke oven defendant has the burden of proof, and gas, or any gaseous fuel produced in a the merits of which are independently feedwater pumps and any associated gas compressors (air separation unit main process which might result in highly and objectively evaluated in a judicial variable sulfur content or heating value. or administrative proceeding. compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of Net energy output means the gross * * * * * the useful thermal output measured energy output minus the parasitic load Boiler operating day for units relative to ISO conditions that is not associated with power production. constructed, reconstructed, or modified used to generate additional electrical or Parasitic load includes, but is not before February 29, 2005, means a 24- mechanical output or to enhance the limited to, the power required to operate hour period during which fossil fuel is performance of the unit (i.e., steam the equipment used for fuel delivery combusted in a steam-generating unit delivered to an industrial process); systems, air pollution control systems, for the entire 24 hours. For units wastewater treatment systems, ash (4) For a IGCC electric utility constructed, reconstructed, or modified handling and disposal systems, and generating unit that coproduces after February 28, 2005, boiler operating other controls (i.e., pumps, fans, chemicals constructed, reconstructed, or day means a 24-hour period between 12 compressors, motors, instrumentation, modified after May 3, 2011, the gross midnight and the following midnight and other ancillary equipment required useful work performed is the gross during which any fuel is combusted at to operate the affected facility). any time in the steam-generating unit. It electrical or mechanical output from the unit minus electricity used to power the * * * * * is not necessary for fuel to be combusted Out-of-control period means any the entire 24-hour period. feedwater pumps and any associated gas compressors (air separation unit main period beginning with the quadrant * * * * * corresponding to the completion of a Combined heat and power, also compressor, oxygen compressor, and nitrogen compressor) that are associated daily calibration error, linearity check, known as ‘‘cogeneration,’’ means a or quality assurance audit that indicates steam-generating unit that with power production plus 75 percent of the useful thermal output measured that the instrument is not measuring simultaneously produces both electric and recording within the applicable (and mechanical) and useful thermal relative to ISO conditions that is not used to generate additional electrical or performance specifications and ending energy from the same primary energy with the quadrant corresponding to the source. mechanical output or to enhance the performance of the unit (i.e., steam completion of an additional calibration * * * * * delivered to an industrial process). error, linearity check, or quality Gaseous fuel means any fuel that is Auxiliary loads that are associated with assurance audit following corrective present as a gas at standard conditions power production are determined based action that demonstrates that the and includes, but is not limited to, on the energy in the coproduced instrument is measuring and recording natural gas, refinery fuel gas, process chemicals compared to the energy of the within the applicable performance gas, coke-oven gas, synthetic gas, and syngas combusted in combustion specifications. gasified coal. turbine engine and associated duct Petroleum for facilities constructed, * * * * * burners. reconstructed, or modified before May Gross energy output means: 4, 2011, means crude oil or a fuel (1) For facilities constructed, * * * * * derived from crude oil, including, but reconstructed, or modified before May Integrated gasification combined not limited to, distillate oil, and residual 4, 2011, the gross electrical or cycle electric utility steam generating oil. For units constructed, mechanical output from the affected unit or IGCC electric utility steam reconstructed, or modified after May 3, facility plus 75 percent of the useful generating unit means an electric utility 2011, petroleum means crude oil or a thermal output measured relative to ISO combined cycle gas turbine that is fuel derived from crude oil, including, conditions that is not used to generate designed to burn fuels containing 50 but not limited to, distillate oil, residual additional electrical or mechanical percent (by heat input) or more solid- oil, and petroleum coke. output or to enhance the performance of derived fuel not meeting the definition Petroleum coke, also known as the unit (i.e., steam delivered to an of natural gas. The Administrator may ‘‘petcoke,’’ means a carbonization industrial process); waive the 50 percent solid-derived fuel product of high-boiling hydrocarbon (2) For facilities constructed, requirement during periods of the fractions obtained in petroleum reconstructed, or modified after May 3, gasification system construction or processing (heavy residues). Petroleum

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coke is typically derived from oil emissions according to the requirements specified in paragraphs (e)(1) and (2) of refinery coker units or other cracking of this subpart is exempt from the this section. processes. opacity standard specified in this (1) On and after the date on which the Potential combustion concentration paragraph (b) of this section. initial performance test is completed or means the theoretical emissions (2) An owner or operator of an required to be completed under § 60.8, (nanograms per joule (ng/J), lb/MMBtu affected facility that combusts only whichever date comes first, no owner or heat input) that would result from natural gas is exempt from the opacity operator shall cause to be discharged combustion of a fuel in an uncleaned standard specified in paragraph (b) of into the atmosphere from that affected state without emission control systems. this section. facility at all times except during For sulfur dioxide (SO2) the potential (c) Except as provided in paragraphs periods of startup and shutdown, any combustion concentration is determined (d) and (f) of this section, on and after gases that contain PM in excess of the under § 60.50Da(c). the date on which the initial applicable emissions limit specified in * * * * * performance test is completed or paragraphs (e)(1)(i) or (ii) of this section. Steam generating unit for facilities required to be completed under § 60.8, (i) For an affected facility which constructed, reconstructed, or modified whichever date comes first, no owner or commenced construction or before May 4, 2011, means any furnace, operator of an affected facility that reconstruction, any gases that contain boiler, or other device used for commenced construction, PM in excess of either: combusting fuel for the purpose of reconstruction, or modification after (A) 11 ng/J (0.090 lb/MWh) gross producing steam (including fossil-fuel- February 28, 2005, but before May 4, energy output; or fired steam generators associated with 2011, shall cause to be discharged into (B) 12 ng/J (0.097 lb/MWh) net energy combined cycle gas turbines; nuclear the atmosphere from that affected output. steam generators are not included). For facility any gases that contain PM in (ii) For an affected facility which units constructed, reconstructed, or excess of either: commenced modification, any gases that modified after May 3, 2011, steam (1) 18 ng/J (0.14 lb/MWh) gross energy contain PM in excess of 13 ng/J (0.015 generating unit means any furnace, output; or lb/MMBtu) heat input. boiler, or other device used for (2) 6.4 ng/J (0.015 lb/MMBtu) heat (2) During periods of startup and combusting fuel for the purpose of input derived from the combustion of shutdown, the owner or operator shall producing steam (including fossil-fuel- solid, liquid, or gaseous fuel. meet the work practice standards fired steam generators associated with (d) As an alternative to meeting the specified in Table 3 to subpart UUUUU combined cycle gas turbines; nuclear requirements of paragraph (c) of this of part 63. steam generators are not included) plus section, the owner or operator of an (f) An owner or operator of an affected any integrated combustion turbines and affected facility for which construction, facility that meets the conditions in fuel cells. reconstruction, or modification either paragraphs (f)(1) or (2) of this * * * * * commenced after February 28, 2005, but section is exempt from the PM ■ 13. Section 60.42Da is revised to read before May 4, 2011, may elect to meet emissions limits in this section. as follows: the requirements of this paragraph. On (1) The affected facility combusts only gaseous or liquid fuels (excluding § 60.42Da Standards for particulate matter and after the date on which the initial performance test is completed or residual oil) with potential SO2 (PM). emissions rates of 26 ng/J (0.060 lb/ (a) Except as provided in paragraph (f) required to be completed under § 60.8, whichever date comes first, no owner or MMBtu) or less, and that does not use of this section, on and after the date on a post-combustion technology to reduce which the initial performance test is operator of an affected facility shall emissions of SO2 or PM. completed or required to be completed cause to be discharged into the atmosphere from that affected facility (2) The affected facility is operated under § 60.8, whichever date comes under a PM commercial demonstration first, an owner or operator of an affected any gases that contain PM in excess of: (1) 13 ng/J (0.030 lb/MMBtu) heat permit issued by the Administrator facility shall not cause to be discharged according to the provisions of § 60.47Da. into the atmosphere from any affected input derived from the combustion of ■ 14. Section 60.43Da is amended as facility for which construction, solid, liquid, or gaseous fuel, and follows: reconstruction, or modification (2) For an affected facility that commenced construction or ■ a. The section heading is revised. commenced before March 1, 2005, any ■ b. By revising paragraphs (a)(1) and gases that contain PM in excess of 13 reconstruction, 0.1 percent of the combustion concentration determined (2). ng/J (0.030 lb/MMBtu) heat input. ■ c. By adding paragraphs (a)(3) and (4). (b) Except as provided in paragraphs according to the procedure in ■ d. By removing and reserving (b)(1) and (b)(2) of this section, on and § 60.48Da(o)(5) (99.9 percent reduction) paragraph (c). after the date the initial PM performance when combusting solid, liquid, or ■ gaseous fuel, or e. By revising paragraph (f). test is completed or required to be ■ f. By revising paragraph (i). (3) For an affected facility that completed under § 60.8, whichever date ■ g. By revising paragraph (k). comes first, an owner or operator of an commenced modification, 0.2 percent of ■ h. By adding paragraph (l). affected facility shall not cause to be the combustion concentration ■ i. By adding paragraph (m). discharged into the atmosphere any determined according to the procedure gases which exhibit greater than 20 in § 60.48Da(o)(5) (99.8 percent § 60.43Da Standards for sulfur dioxide percent opacity (6-minute average), reduction) when combusting solid, (SO2). except for one 6-minute period per hour liquid, or gaseous fuel. (a) * * * of not more than 27 percent opacity. (e) Except as provided in paragraph (f) (1) 520 ng/J (1.20 lb/MMBtu) heat (1) An owner or operator of an of this section, the owner or operator of input and 10 percent of the potential affected facility that elects to install, an affected facility that commenced combustion concentration (90 percent calibrate, maintain, and operate a construction, reconstruction, or reduction); continuous emissions monitoring modification commenced after May 3, (2) 30 percent of the potential system (CEMS) for measuring PM 2011, shall meet the requirements combustion concentration (70 percent

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reduction), when emissions are less (iii) 10 percent of the potential (i) 180 ng/J (1.4 lb/MWh) gross energy than 260 ng/J (0.60 lb/MMBtu) heat combustion concentration (90 percent output; or input; reduction). (ii) 10 percent of the potential (3) 180 ng/J (1.4 lb/MWh) gross energy * * * * * combustion concentration (90 percent output; or (k) On and after the date on which the reduction). (4) 65 ng/J (0.15 lb/MMBtu) heat initial performance test is completed or (m) On and after the date on which input. required to be completed under § 60.8, the initial performance test is completed * * * * * whichever date comes first, no owner or or required to be completed under operator of an affected facility located in (f) The SO standards under this § 60.8, whichever date comes first, no 2 a noncontinental area for which section do not apply to an owner or owner or operator of an affected facility construction, reconstruction, or operator of an affected facility that is located in a noncontinental area for modification commenced after February which construction, reconstruction, or operated under an SO commercial 2 28, 2005, but before May 4, 2011, shall modification commenced after May 3, demonstration permit issued by the cause to be discharged into the 2011, shall cause to be discharged into Administrator in accordance with the atmosphere from that affected facility the atmosphere from that affected provisions of § 60.47Da. any gases that contain SO2 in excess of facility any gases that contain SO2 in * * * * * the applicable emissions limit specified excess of the applicable emissions limit (i) Except as provided in paragraphs in paragraphs (k)(1) and (2) of this specified in paragraphs (m)(1) and (2) of (j) and (k) of this section, on and after section. this section. the date on which the initial (1) For an affected facility that burns (1) For an affected facility that burns performance test is completed or solid or solid-derived fuel, the owner or solid or solid-derived fuel, the owner or required to be completed under § 60.8, operator shall not cause to be operator shall not cause to be whichever date comes first, no owner or discharged into the atmosphere any discharged into the atmosphere any gases that contain SO2 in excess of 520 operator of an affected facility for which gases that contain SO2 in excess of 520 construction, reconstruction, or ng/J (1.2 lb/MMBtu) heat input. ng/J (1.2 lb/MMBtu) heat input. (2) For an affected facility that burns modification commenced after February (2) For an affected facility that burns other than solid or solid-derived fuel, 28, 2005, but before May 4, 2011, shall other than solid or solid-derived fuel, the owner or operator shall not cause to cause to be discharged into the the owner or operator shall not cause to be discharged into the atmosphere any atmosphere from that affected facility, be discharged into the atmosphere any any gases that contain SO2 in excess of gases that contain SO2 in excess of 230 gases that contain SO2 in excess of 230 the applicable emissions limit specified ng/J (0.54 lb/MMBtu) heat input. (l) Except as provided in paragraphs ng/J (0.54 lb/MMBtu) heat input. in paragraphs (i)(1) through (3) of this ■ (j) and (m) of this section, on and after 15. Section 60.44Da is revised to read section. as follows: (1) For an affected facility which the date on which the initial commenced construction, any gases that performance test is completed or § 60.44Da Standards for nitrogen oxides required to be completed under § 60.8, contain SO in excess of either: (NOX). 2 whichever date comes first, no owner or (a) Except as provided in paragraph (i) 180 ng/J (1.4 lb/MWh) gross energy operator of an affected facility for which (h) of this section, on and after the date output; or construction, reconstruction, or on which the initial performance test is (ii) 5 percent of the potential modification commenced after May 3, completed or required to be completed combustion concentration (95 percent 2011, shall cause to be discharged into under § 60.8, whichever date comes reduction). the atmosphere from that affected first, no owner or operator subject to the (2) For an affected facility which facility, any gases that contain SO in 2 provisions of this subpart shall cause to commenced reconstruction, any gases excess of the applicable emissions limit be discharged into the atmosphere from that contain SO2 in excess of either: specified in paragraphs (l)(1) and (2) of any affected facility for which (i) 180 ng/J (1.4 lb/MWh) gross energy this section. construction, reconstruction, or output; (1) For an affected facility which commenced construction or modification commenced before July 10, (ii) 65 ng/J (0.15 lb/MMBtu) heat 1997 any gases that contain NO input; or reconstruction, any gases that contain X (expressed as NO2) in excess of the (iii) 5 percent of the potential SO2 in excess of either: (i) 130 ng/J (1.0 lb/MWh) gross energy applicable emissions limit in paragraphs combustion concentration (95 percent (a)(1) and (2) of this section. reduction). output; or (ii) 140 ng/J (1.2 lb/MWh) net energy (1) The owner or operator shall not (3) For an affected facility which output; or cause to be discharged into the commenced modification, any gases that (iii) 3 percent of the potential atmosphere any gases that contain NOX contain SO2 in excess of either: combustion concentration (97 percent in excess of the emissions limit listed in (i) 180 ng/J (1.4 lb/MWh) gross energy reduction). the following table as applicable to the output; (2) For an affected facility which fuel type combusted and as determined (ii) 65 ng/J (0.15 lb/MMBtu) heat commenced modification, any gases that on a 30-boiler operating day rolling input; or contain SO2 in excess of either: average basis.

Emission limit for heat Fuel type input ng/J lb/MMBtu

Gaseous fuels: Coal-derived fuels ...... 210 0.50 All other fuels ...... 86 0.20 Liquid fuels:

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Emission limit for heat Fuel type input ng/J lb/MMBtu

Coal-derived fuels ...... 210 0.50 Shale oil ...... 210 0.50 All other fuels ...... 130 0.30 Solid fuels: Coal-derived fuels ...... 210 0.50 Any fuel containing more than 25%, by weight, coal refuse ...... (1) (1) Any fuel containing more than 25%, by weight, lignite if the lignite is mined in North Dakota, South Dakota, or Mon- tana, and is combusted in a slag tap furnace 2 ...... 340 0.80 Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat input emission limit 2 ...... 260 0.60 Subbituminous coal ...... 210 0.50 Bituminous coal ...... 260 0.60 Anthracite coal ...... 260 0.60 All other fuels ...... 260 0.60

1 Exempt from NOX standards and NOX monitoring requirements. 2 Any fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel.

(2) When two or more fuels are emissions limit (En) is determined by combusted simultaneously in an proration using the following formula: affected facility, the applicable

Where: contain NOX in excess of 200 ng/J (1.6 (ii) 65 ng/J (0.15 lb/MMBtu) heat

En = Applicable NOX emissions limit when lb/MWh) gross energy output. input. multiple fuels are combusted (2) For an affected facility which (f) On and after the date on which the simultaneously (ng/J heat input); commenced reconstruction, any gases initial performance test is completed or w = Percentage of total heat input derived that contain NOX in excess of 65 ng/J required to be completed under § 60.8, from the combustion of fuels subject to (0.15 lb/MMBtu) heat input. whichever date comes first, the owner the 86 ng/J heat input standard; (e) Except as provided in paragraphs or operator of an IGCC electric utility x = Percentage of total heat input derived (f) and (h) of this section, on and after steam generating unit subject to the from the combustion of fuels subject to the date on which the initial the 130 ng/J heat input standard; provisions of this subpart and for which performance test is completed or construction, reconstruction, or y = Percentage of total heat input derived required to be completed under § 60.8, from the combustion of fuels subject to modification commenced after February the 210 ng/J heat input standard; whichever date comes first, no owner or 28, 2005 but before May 4, 2011, shall z = Percentage of total heat input derived operator of an affected facility that meet the requirements specified in from the combustion of fuels subject to commenced construction, paragraphs (f)(1) through (3) of this the 260 ng/J heat input standard; and reconstruction, or modification after section. v = Percentage of total heat input delivered February 28, 2005 but before May 4, (1) Except as provided for in from the combustion of fuels subject to 2011, shall cause to be discharged into the 340 ng/J heat input standard. paragraphs (f)(2) and (3) of this section, the atmosphere from that affected the owner or operator shall not cause to (b) [Reserved] facility any gases that contain NOX be discharged into the atmosphere any (c) [Reserved] (expressed as NO2) in excess of the gases that contain NO (expressed as applicable emissions limit specified in X (d) Except as provided in paragraph NO2) in excess of 130 ng/J (1.0 lb/MWh) paragraphs (e)(1) through (3) of this (h) of this section, on and after the date gross energy output. section as determined on a 30-boiler on which the initial performance test is (2) When burning liquid fuel operating day rolling average basis. completed or required to be completed (1) For an affected facility which exclusively or in combination with under § 60.8, whichever date comes commenced construction, any gases that solid-derived fuel such that the liquid first, no owner or operator of an affected contain NO in excess of 130 ng/J (1.0 fuel contributes 50 percent or more of facility that commenced construction, X lb/MWh) gross energy output. the total heat input to the combined reconstruction, or modification after (2) For an affected facility which cycle combustion turbine, the owner or July 9, 1997, but before March 1, 2005, commenced reconstruction, any gases operator shall not cause to be shall cause to be discharged into the discharged into the atmosphere any that contain NOX in excess of either: atmosphere from that affected facility (i) 130 ng/J (1.0 lb/MWh) gross energy gases that contain NOX (expressed as any gases that contain NOX (expressed output; or NO2) in excess of 190 ng/J (1.5 lb/MWh) as NO2) in excess of the applicable (ii) 47 ng/J (0.11 lb/MMBtu) heat gross energy output. emissions limit specified in paragraphs input. (3) In cases when during a 30-boiler (d)(1) and (2) of this section as (3) For an affected facility which operating day rolling average determined on a 30-boiler operating day commenced modification, any gases that compliance period liquid fuel is burned rolling average basis. contain NOX in excess of either: in such a manner to meet the conditions (1) For an affected facility which (i) 180 ng/J (1.4 lb/MWh) gross energy in paragraph (f)(2) of this section for commenced construction, any gases that output; or only a portion of the clock hours in the

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30-day compliance period, the owner or § 60.45Da Alternative standards for (c) An owner or operator of an operator shall not cause to be combined nitrogen oxides (NOX) and affected facility that uses fluidized bed discharged into the atmosphere any carbon monoxide (CO). combustion (atmospheric or gases that contain NOX (expressed as (a) The owner or operator of an pressurized) and who is issued a NO2) in excess of the computed affected facility that commenced commercial demonstration permit by weighted-average emissions limit based construction, reconstruction, or the Administrator is not subject to the on the proportion of gross energy output modification after May 3, 2011 as SO2 emission reduction requirements (in MWh) generated during the alternate to meeting the applicable NOX under § 60.43Da(a) but must, as a compliance period for each of emissions emissions limits specified in § 60.44Da minimum, reduce SO2 emissions to 15 limits in paragraphs (f)(1) and (2) of this may elect to meet the applicable percent of the potential combustion section. standards for combined NOX and CO concentration (85 percent reduction) on (g) Except as provided in paragraphs specified in paragraph (b) of this a 30-day rolling average basis and to less (h) of this section and § 60.45Da, on and section. than 520 ng/J (1.20 lb/MMBtu) heat after the date on which the initial (b) On and after the date on which the input on a 30-day rolling average basis. initial performance test is completed or performance test is completed or * * * * * required to be completed under § 60.8 required to be completed under § 60.8, (f) An owner or operator of an affected no owner or operator of an affected whichever date comes first, no owner or facility that uses a pressurized fluidized facility that commenced construction, operator of an affected facility that bed or a multi-pollutant emissions reconstruction, or modification after commenced construction, controls system who is issued a May 3, 2011, shall cause to be reconstruction, or modification after commercial demonstration permit by discharged into the atmosphere from May 3, 2011, shall cause to be the Administrator is not subject to the that affected facility any gases that discharged into the atmosphere from total PM emission reduction contain NO (expressed as NO ) plus that affected facility any gases that X 2 requirements under § 60.42Da but must, CO in excess of the applicable emissions contain NOX (expressed as NO2) in as a minimum, reduce PM emissions to limit specified in paragraphs (b)(1) excess of the applicable emissions limit less than 6.4 ng/J (0.015 lb/MMBtu) heat through (3) of this section as determined specified in paragraphs (g)(1) through input. (3) of this section. on a 30-boiler operating day rolling average basis. (g) An owner or operator of an (1) For an affected facility which (1) For an affected facility which affected facility that uses a pressurized commenced construction or commenced construction or fluidized bed or a multi-pollutant reconstruction, any gases that contain reconstruction, any gases that contain emissions controls system who is issued NOX in excess of either: NOX plus CO in excess of either: a commercial demonstration permit by (i) 88 ng/J (0.70 lb/MWh) gross energy (i) 140 ng/J (1.1 lb/MWh) gross energy the Administrator is not subject to the output; or output; or SO2 standards or emission reduction (ii) 95 ng/J (0.76 lb/MWh) net energy (ii) 150 ng/J (1.2 lb/MWh) net energy requirements under § 60.43Da but must, output. output. as a minimum, reduce SO2 emissions to (2) For an affected facility which (2) For an affected facility which 5 percent of the potential combustion commenced construction or commenced construction or concentration (95 percent reduction) or reconstruction and that burns 75 reconstruction and that burns 75 to less than 180 ng/J (1.4 lb/MWh) gross percent or more coal refuse (by heat percent or more coal refuse (by heat energy output on a 30-boiler operating input) on a 12-month rolling average input) on a 12-month rolling average day rolling average basis. basis, any gases that contain NOX plus (h) An owner or operator of an basis, any gases that contain NOX in excess of either: CO in excess of either: affected facility that uses a pressurized (i) 160 ng/J (1.3 lb/MWh) gross energy fluidized bed or a multi-pollutant (i) 110 ng/J (0.85 lb/MWh) gross output; or emissions control system or advanced energy output; or (ii) 170 ng/J (1.4 lb/MWh) net energy combustion controls who is issued a (ii) 120 ng/J (0.92 lb/MWh) net energy output. commercial demonstration permit by output. (3) For an affected facility which the Administrator is not subject to the commenced modification, any gases that (3) For an affected facility which NOX standards or emission reduction commenced modification, any gases that contain NOX plus CO in excess of 190 requirements under § 60.44Da but must, ng/J (1.5 lb/MWh) gross energy output. contain NOX in excess of 140 ng/J (1.1 as a minimum, reduce NOX emissions to lb/MWh) gross energy output. ■ 17. Section 60.47Da is amended as less than 130 ng/J (1.0 lb/MWh) or the (h) The NOX emissions limits under follows: combined NOX plus CO emissions to this section do not apply to an owner or ■ a. By revising paragraph (c). less than 180 ng/J (1.4 lb/MWh) gross ■ operator of an affected facility which is b. By adding paragraph (f). energy output on a 30-boiler operating ■ c. By adding paragraph (g). operating under a commercial ■ day rolling average basis. demonstration permit issued by the d. By adding paragraph (h). ■ e. By adding paragraph (i). (i) Commercial demonstration permits Administrator in accordance with the may not exceed the following equivalent provisions of § 60.47Da. § 60.47Da Commercial demonstration MW electrical generation capacity for ■ 16. Section 60.45Da is revised to read permit. any one technology category listed in as follows: * * * * * the following table.

Equivalent electrical Technology Pollutant capacity (MW elec- trical output)

Multi-pollutant Emission Control ...... SO2 ...... 1,000

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Equivalent electrical Technology Pollutant capacity (MW elec- trical output)

Multi-pollutant Emission Control ...... NOX ...... 1,000 Multi-pollutant Emission Control ...... PM ...... 1,000 Pressurized Fluidized Bed Combustion ...... SO2 ...... 1,000 Pressurized Fluidized Bed Combustion ...... NOX ...... 1,000 Pressurized Fluidized Bed Combustion ...... PM ...... 1,000 Advanced Combustion Controls ...... NOX ...... 1,000

■ 18. Section 60.48Da is amended as calculated to demonstrate compliance affected facilities for which follows: with the standards. construction, modification, or ■ a. By revising paragraphs (a) through (c) For the initial performance test reconstruction commenced after May 3, (g). required under § 60.8, compliance with 2011, compliance with applicable SO2 ■ b. By revising paragraph (i). the applicable SO2 emissions limits and percentage reduction requirements is ■ c. By revising paragraph (k)(1)(i). percentage reduction requirements determined based on the ‘‘as fired’’ total ■ d. By revising paragraph (k)(2)(i). under § 60.43Da, the NOX emissions potential emissions and the total outlet limits under § 60.44Da, and the NO ■ e. By revising paragraph (k)(2)(iv). X SO2 emissions for the 30 successive ■ f. By removing and reserving plus CO emissions limits under boiler operating days. § 60.45Da is based on the average paragraph (l). (f) For affected facilities for which emission rates for SO2, NOX, CO, and ■ g. By revising paragraph (m). construction, modification, or percent reduction for SO2 for the first 30 ■ h. By revising paragraph (n). reconstruction commenced before May ■ successive boiler operating days. The i. By revising paragraphs (p)(5), (7), initial performance test is the only test 4, 2011, compliance with applicable and (8). in which at least 30 days prior notice is daily average PM emissions limits is ■ j. By adding paragraph (r). required unless otherwise specified by determined by calculating the ■ k. By adding paragraph (s). the Administrator. The initial arithmetic average of all hourly § 60.48Da Compliance provisions. performance test is to be scheduled so emission rates for PM each boiler that the first boiler operating day of the operating day, except for data obtained (a) For affected facilities for which 30 successive boiler operating days is during startup, shutdown, and construction, modification, or completed within 60 days after malfunction. Daily averages are only reconstruction commenced before May achieving the maximum production rate calculated for boiler operating days that 4, 2011, the applicable PM emissions at which the affected facility will be have non-out-of-control data for at least limit and opacity standard under operated, but not later than 180 days 18 hours of unit operation during which § 60.42Da, SO2 emissions limit under after initial startup of the facility. the standard applies. Instead, all of the § 60.43Da, and NOX emissions limit (d) For affected facilities for which non-out-of-control hourly emission rates under § 60.44Da apply at all times construction, modification, or of the operating day(s) not meeting the except during periods of startup, reconstruction commenced before May minimum 18 hours non-out-of-control shutdown, or malfunction. For affected 4, 2011, compliance with applicable 30- data daily average requirement are facilities for which construction, boiler operating day rolling average SO2 averaged with all of the non-out-of- modification, or reconstruction and NOX emissions limits is determined control hourly emission rates of the next commenced after May 3, 2011, the by calculating the arithmetic average of boiler operating day with 18 hours or applicable SO emissions limit under 2 all hourly emission rates for SO2 and more of non-out-of-control PM CEMS § 60.43Da, NO emissions limit under X NOX for the 30 successive boiler data to determine compliance. For § 60.44Da, and NO plus CO emissions X operating days, except for data obtained affected facilities for which limit under § 60.45Da apply at all times. during startup, shutdown, or construction, modification, or The applicable PM emissions limit and malfunction. For affected facilities for reconstruction commenced after May 3, opacity standard under § 60.42Da apply which construction, modification, or 2011, compliance with applicable daily at all times except during periods of reconstruction commenced after May 3, startup and shutdown. average PM emissions limits is 2011, compliance with applicable 30- determined by dividing the sum of the (b) After the initial performance test boiler operating day rolling average SO2 PM emissions for the 30 successive required under § 60.8, compliance with and NOX emissions limits is determined the applicable SO emissions limit and boiler operating days by the sum of the 2 by dividing the sum of the SO2 and NOX gross useful output or net energy output, percentage reduction requirements emissions for the 30 successive boiler under § 60.43Da, NO emissions limit as applicable, for the 30 successive X operating days by the sum of the gross boiler operating days. under § 60.44Da, and NOX plus CO energy output or net energy output, as emissions limit under § 60.45Da is applicable, for the 30 successive boiler (g) For affected facilities for which based on the average emission rate for operating days. construction, modification, or 30 successive boiler operating days. A (e) For affected facilities for which reconstruction commenced after May 3, separate performance test is completed construction, modification, or 2011, compliance with applicable 30- at the end of each boiler operating day reconstruction commenced before May boiler operating day rolling average NOX after the initial performance test, and a 4, 2011, compliance with applicable plus CO emissions limit is determined new 30-boiler operating day rolling SO2 percentage reduction requirements by dividing the sum of the NOX plus CO average emission rate for both SO2, NOX is determined based on the average inlet emissions for the 30 successive boiler or NOX plus CO as applicable, and a and outlet SO2 emission rates for the 30 operating days by the sum of the gross new percent reduction for SO2 are successive boiler operating days. For energy output or net energy output, as

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applicable, for the 30 successive boiler flow rate (measured in scfh, according (d)), by the hourly heat input rate operating days. to the provisions of § 60.49Da(l) or (measured according to the provisions * * * * * § 60.49Da(m)), divided by the average of § 60.49Da(n)), and dividing the result (i) Compliance provisions for sources hourly gross energy output (measured by the average gross energy output subject to § 60.44Da(d)(1), (e)(1), according to the provisions of (measured according to the provisions (e)(2)(i), (e)(3)(i), (f), or (g). The owner or § 60.49Da(k)) or the average hourly net of § 60.49Da(k)) or the average hourly operator shall calculate NOX emissions energy output, as applicable. net energy output, as applicable. as 1.194 × 10¥7 lb/scf-ppm times the Alternatively, for oil-fired and gas-fired (k) * * * average hourly NOX output units, NOX emissions may be calculated (1) * * * concentration in ppm (measured by multiplying the hourly NOX emission (i) The emission rate (E) of NOX shall according to the provisions of rate in lb/MMBtu (measured by the be computed using Equation 2 in this § 60.49Da(c)), times the average hourly CEMS required under § 60.49Da(c) and section:

Where: Qsg = Average hourly volumetric flow rate of h = Average hourly fraction of the total heat

E = Emission rate of NOX from the duct exhaust gas from steam generating unit, input to the steam generating unit burner, ng/J (lb/MWh) gross energy dscm/h (dscf/h); derived from the combustion of fuel in output; Qte = Average hourly volumetric flow rate of the affected duct burner. Csg = Average hourly concentration of NOX exhaust gas from combustion turbine, * * * * * exiting the steam generating unit, ng/ dscm/h (dscf/h); dscm (lb/dscf); (2) * * * Osg = Average hourly gross energy output (i) The emission rate (E) of NOX shall Cte = Average hourly concentration of NOX in from steam generating unit, J/h (MW); the turbine exhaust upstream from duct be computed using Equation 3 in this and burner, ng/dscm (lb/dscf); section:

Where: Occ = Average hourly gross energy output (lb/h) of NOX emissions by installing, E = Emission rate of NOX from the duct from entire combined cycle unit, J/h operating, and maintaining continuous burner, ng/J (lb/MWh) gross energy (MW). fuel flowmeters following the output; * * * * * appropriate measurements procedures Csg = Average hourly concentration of NOX specified in appendix D of part 75 of exiting the steam generating unit, ng/ (iv) The owner or operator may, in dscm (lb/dscf); lieu of installing, operating, and this chapter. If this compliance option is Qsg = Average hourly volumetric flow rate of recording data from the continuous flow selected, the emission rate (E) of NOX exhaust gas from steam generating unit, monitoring system specified in shall be computed using Equation 4 in dscm/h (dscf/h); and § 60.49Da(l), determine the mass rate this section:

Where: (l)(1)(i), (l)(1)(ii), or (l)(2). The owner or hourly heat input rate (measured E = Emission rate of NOX from the duct operator shall calculate SO2 emissions according to the provisions of burner, ng/J (lb/MWh) gross energy as 1.660 × 10¥7 lb/scf-ppm times the § 60.49Da(n)), and dividing the result by output; average hourly SO2 output the average gross energy output ERsg = Average hourly emission rate of NOX concentration in ppm (measured (measured according to the provisions exiting the steam generating unit heat according to the provisions of of § 60.49Da(k)) or the average hourly input calculated using appropriate F § 60.49Da(b)), times the average hourly net energy output, as applicable. factor as described in Method 19 of flow rate (measured according to the (n) Compliance provisions for sources appendix A of this part, ng/J (lb/ provisions of § 60.49Da(l) or subject to § 60.42Da(c)(1) or (e)(1)(i). MMBtu); § 60.49Da(m)), divided by the average The owner or operator shall calculate Hcc = Average hourly heat input rate of entire combined cycle unit, J/h (MMBtu/h); and hourly gross energy output (measured PM emissions by multiplying the Occ = Average hourly gross energy output according to the provisions of average hourly PM output concentration from entire combined cycle unit, J/h § 60.49Da(k)) or the average hourly net (measured according to the provisions (MW). energy output, as applicable. of § 60.49Da(t)), by the average hourly Alternatively, for oil-fired and gas-fired flow rate (measured according to the * * * * * units, SO2 emissions may be calculated provisions of § 60.49Da(l) or (m) Compliance provisions for by multiplying the hourly SO2 emission § 60.49Da(m)), and dividing by the sources subject to § 60.43Da(i)(1)(i), rate (in lb/MMBtu), measured by the average hourly gross energy output (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), (j)(3)(i), CEMS required under § 60.49Da, by the (measured according to the provisions

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of § 60.49Da(k)) or the average hourly (measured according to the provisions (vi) All emissions monitoring and net energy output, as applicable. of § 60.49Da(k)) or the average hourly control systems were kept in operation * * * * * net energy output, as applicable. if at all possible, consistent with safety (p) * * * (3) Calculate NOX plus CO emissions and good air pollution control practices; (5) At a minimum, non-out-of-control by summing the NOX emissions results and CEMS hourly averages shall be obtained from paragraph (r)(1) of this section plus (vii) All of the actions in response to for 75 percent of all operating hours on the CO emissions results from paragraph the excess emissions were documented a 30-boiler operating day rolling average (r)(2) of this section. by properly signed, contemporaneous basis. Beginning on January 1, 2012, (s) Affirmative defense for exceedance operating logs; and non-out-of-control CEMS hourly of emissions limit during malfunction. (viii) At all times, the facility was averages shall be obtained for 90 percent In response to an action to enforce the operated in a manner consistent with of all operating hours on a 30-boiler standards set forth in paragraph good practices for minimizing operating day rolling average basis. §§ 60.42Da, 60.43Da, 60.44Da, and emissions; and (i) At least two data points per hour 60.45Da, you may assert an affirmative (ix) A written root cause analysis has shall be used to calculate each 1-hour defense to a claim for civil penalties for been prepared, the purpose of which is arithmetic average. exceedances of such standards that are to determine, correct, and eliminate the (ii) [Reserved] caused by malfunction, as defined at 40 primary causes of the malfunction and * * * * * CFR 60.2. Appropriate penalties may be the excess emissions resulting from the (7) All non-out-of-control CEMS data assessed, however, if you fail to meet malfunction event at issue. The analysis shall be used in calculating average your burden of proving all of the shall also specify, using best monitoring emission concentrations even if the requirements in the affirmative defense methods and engineering judgment, the minimum CEMS data requirements of as specified in paragraphs (s)(1) and (2) amount of excess emissions that were paragraph (j)(5) of this section are not of this section. The affirmative defense the result of the malfunction. met. shall not be available for claims for (2) Notification. The owner or (8) When PM emissions data are not injunctive relief. operator of the affected source obtained because of CEMS breakdowns, (1) To establish the affirmative experiencing an exceedance of its repairs, calibration checks, and zero and defense in any action to enforce such a emission limit(s) during a malfunction span adjustments, emissions data shall limit, you must timely meet the shall notify the Administrator by be obtained by using other monitoring notification requirements in paragraph telephone or facsimile (FAX) systems as approved by the (s)(2) of this section, and must prove by transmission as soon as possible, but no Administrator or EPA Reference Method a preponderance of evidence that: later than two business days after the 19 of appendix A of this part to provide, (i) The excess emissions: initial occurrence of the malfunction or, (A) Were caused by a sudden, as necessary, non-out-of-control if it is not possible to determine within infrequent, and unavoidable failure of emissions data for a minimum of 90 two business days whether the air pollution control and monitoring percent (only 75 percent is required malfunction caused or contributed to an equipment, process equipment, or a prior to January 1, 2012) of all operating exceedance, no later than two business process to operate in a normal or usual hours per 30-boiler operating day rolling days after the owner or operator knew manner; and average. or should have known that the (B) Could not have been prevented * * * * * malfunction caused or contributed to an through careful planning, proper design, exceedance, but, in no event later than (r) Compliance provisions for sources or better operation and maintenance subject to § 60.45Da. To determine two business days after the end of the practices; and averaging period, if it wishes to avail compliance with the NOX plus CO (C) Did not stem from any activity or itself of an affirmative defense to civil emissions limit, the owner or operator event that could have been foreseen and penalties for that malfunction. The shall use the procedures specified in avoided, or planned for; and paragraphs (r)(1) through (3) of this (D) Were not part of a recurring owner or operator seeking to assert an section. pattern indicative of inadequate design, affirmative defense shall also submit a written report to the Administrator (1) Calculate NOX emissions as 1.194 operation, or maintenance; and ¥ × 10 7 lb/scf-ppm times the average (ii) Repairs were made as within 45 days of the initial occurrence of the exceedance of the standard in hourly NOX output concentration in expeditiously as possible when the ppm (measured according to the applicable emissions limits were being § 63.9991 to demonstrate, with all provisions of § 60.49Da(c)), times the exceeded. Off-shift and overtime labor necessary supporting documentation, average hourly flow rate (measured in were used, to the extent practicable to that it has met the requirements set forth scfh, according to the provisions of make these repairs; and in paragraph (s)(1) of this section. The § 60.49Da(l) or § 60.49Da(m)), divided (iii) The frequency, amount, and owner or operator may seek an by the average hourly gross energy duration of the excess emissions extension of this deadline for up to 30 output (measured according to the (including any bypass) were minimized additional days by submitting a written provisions of § 60.49Da(k)) or the to the maximum extent practicable request to the Administrator before the average hourly net energy output, as during periods of such emissions; and expiration of the 45 day period. Until a applicable. (iv) If the excess emissions resulted request for an extension has been (2) Calculate CO emissions by from a bypass of control equipment or approved by the Administrator, the multiplying the average hourly CO a process, then the bypass was owner or operator is subject to the output concentration (measured unavoidable to prevent loss of life, requirement to submit such report according to the provisions of personal injury, or severe property within 45 days of the initial occurrence § 60.49Da(u), by the average hourly flow damage; and of the exceedance. rate (measured according to the (v) All possible steps were taken to ■ 19. Section 60.49Da is amended as provisions of § 60.49Da(l) or minimize the impact of the excess follows: § 60.49Da(m)), and dividing by the emissions on ambient air quality, the ■ a. By revising paragraphs (a)(1) and average hourly gross energy output environment, and human health; and (2).

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■ b. By revising paragraph (a)(3) (iii) The affected facility meets all of from the date that the most recent introductory text. the conditions specified in paragraphs performance test was conducted or ■ c. By revising paragraph (a)(3)(ii). (a)(2)(iii)(A) through (C) of this section. within 45 days of the next day that fuel ■ d. By revising paragraph (a)(3)(iii)(B). (A) No post-combustion technology with an opacity standard is combusted, ■ e. By adding paragraph (a)(4). (except a wet scrubber) is used for whichever is later; or ■ f. By revising paragraph (b) reducing PM, SO2, or CO emissions; (C) If the maximum 6-minute average introductory text. (B) Only natural gas, gaseous fuels, or opacity is greater than 10 percent, a ■ g. By revising paragraph (b)(2). fuel oils that contain less than or equal subsequent Method 9 of appendix A–4 ■ h. By revising paragraph (e). to 0.30 weight percent sulfur are of this part performance test must be ■ i. By revising paragraph (k) burned; and completed within 45 calendar days from introductory text. (C) Emissions of CO discharged to the the date that the most recent ■ j. By revising paragraph (k)(3). atmosphere are maintained at levels less performance test was conducted. ■ than or equal to 1.4 lb/MWh on a boiler k. By revising paragraph (l). (iii) * * * ■ l. By removing and reserving operating day average basis as paragraph (p). demonstrated by the use of a CEMS (B) If no visible emissions are ■ m. By removing and reserving measuring CO emissions according to observed for 10 operating days during paragraph (q). the procedures specified in paragraph which an opacity standard is applicable, ■ n. By removing and reserving (u) of this section; or observations can be reduced to once paragraph (r). (iv) The affected facility uses an ESP every 7 operating days during which an ■ o. By revising paragraph (t). and uses an ESP predictive model to opacity standard is applicable. If any ■ p. By revising paragraph (u)(1)(iii). monitor the performance of the ESP visible emissions are observed, daily ■ q. By revising paragraph (v)(4). developed in accordance and operated observations shall be resumed. according to the most current * * * * * § 60.49Da Emission monitoring. requirements in section § 60.48Da of (4) An owner or operator of an (a) * * * this part. affected facility that is subject to an (1) Except as provided for in (3) The owner or operator of an opacity standard under § 60.42a(b) is paragraphs (a)(2) and (4) of this section, affected facility that meets the not required to operate a COMS the owner or operator of an affected conditions in paragraph (a)(2) of this provided that affected facility meets the facility subject to an opacity standard, section may, as an alternative to using conditions in either paragraph (a)(4)(i) shall install, calibrate, maintain, and a COMS, elect to monitor visible or (ii) of this section. operate a COMS, and record the output emissions using the applicable (i) The affected facility combusts only of the system, for measuring the opacity procedures specified in paragraphs gaseous fuels and/or liquid fuels of emissions discharged to the (a)(3)(i) through (iv) of this section. The (excluding residue oil) with a potential atmosphere. If opacity interference due opacity performance test requirement in SO emissions rate no greater than 26 to water droplets exists in the stack (for paragraph (a)(3)(i) must be conducted by 2 ng/J (0.060 lb/MMBtu), and the unit example, from the use of an FGD April 29, 2011, within 45 days after operates according to a written site- system), the opacity is monitored stopping use of an existing COMS, or specific monitoring plan approved by upstream of the interference (at the inlet within 180 days after initial startup of the permitting authority. This to the FGD system). If opacity the facility, whichever is later. monitoring plan must include interference is experienced at all * * * * * procedures and criteria for establishing locations (both at the inlet and outlet of (ii) Except as provided in paragraph and monitoring specific parameters for the SO control system), alternate 2 (a)(3)(iii) or (iv) of this section, the the affected facility indicative of parameters indicative of the PM control owner or operator shall conduct compliance with the opacity standard. system’s performance and/or good subsequent Method 9 of appendix A–4 For testing performed as part of this site- combustion are monitored (subject to of this part performance tests using the specific monitoring plan, the permitting the approval of the Administrator). procedures in paragraph (a)(3)(i) of this authority may require as an alternative (2) As an alternative to the monitoring section according to the applicable to the notification and reporting requirements in paragraph (a)(1) of this schedule in paragraphs (a)(3)(ii)(A) requirements specified in §§ 60.8 and section, an owner or operator of an through (a)(3)(ii)(C) of this section, as 60.11 that the owner or operator submit affected facility that meets the determined by the most recent Method any deviations with the excess conditions in either paragraph (a)(2)(i), 9 of appendix A–4 of this part emissions report required under (ii), (iii), or (iv) of this section may elect performance test results. § 60.51a(d). to monitor opacity as specified in (A) If the maximum 6-minute average paragraph (a)(3) of this section. opacity is less than or equal to 5 (ii) The owner or operator of the (i) The affected facility uses a fabric percent, a subsequent Method 9 of affected facility installs, calibrates, filter (baghouse) to meet the standards appendix A–4 of this part performance operates, and maintains a particulate in § 60.42Da and a bag leak detection test must be completed within 12 matter continuous parametric system is installed and operated calendar months from the date that the monitoring system (PM CPMS) according to the requirements in most recent performance test was according to the requirements specified paragraphs § 60.48Da(o)(4)(i) through conducted or within 45 days of the next in subpart UUUUU of part 63. (v); day that fuel with an opacity standard (b) The owner or operator of an (ii) The affected facility burns only is combusted, whichever is later; affected facility shall install, calibrate, gaseous or liquid fuels (excluding (B) If the maximum 6-minute average maintain, and operate a CEMS, and residual oil) with potential SO2 opacity is greater than 5 percent but less record the output of the system, for emissions rates of 26 ng/J (0.060 lb/ than or equal to 10 percent, a measuring SO2 emissions, except where MMBtu) or less, and does not use a post- subsequent Method 9 of appendix A–4 natural gas and/or liquid fuels combustion technology to reduce of this part performance test must be (excluding residual oil) with potential emissions of SO2 or PM; completed within 3 calendar months SO2 emissions rates of 26 ng/J (0.060 lb/

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MMBtu) or less are the only fuels obtained for at least 90 percent of the integrated or grab sampling and analysis combusted, as follows: operating hours on a 30-boiler operating procedures of Method 3B of appendix A * * * * * day rolling average basis. The 1-hour of this part shall be used to determine (2) For a facility that qualifies under averages are calculated using the data the O2 concentration. The O2 sample the numerical limit provisions of points required in § 60.13(h)(2). shall be obtained simultaneously with, § 60.43Da, SO2 emissions are only * * * * * and at the same traverse points as, the monitored as discharged to the (v) * * * particulate run. If the particulate run atmosphere. (4) As of January 1, 2012, and within has more than 12 traverse points, the O2 * * * * * 90 days after the date of completing traverse points may be reduced to 12 (e) The CEMS under paragraphs (b), each performance test, as defined in provided that Method 1 of appendix A (c), and (d) of this section are operated § 60.8, conducted to demonstrate of this part is used to locate the 12 O2 and data recorded during all periods of compliance with this subpart, you must traverse points. If the grab sampling operation of the affected facility submit relative accuracy test audit (i.e., procedure is used, the O2 concentration including periods of startup, shutdown, reference method) data and performance for the run shall be the arithmetic mean and malfunction, except for CEMS test (i.e., compliance test) data, except of the sample O2 concentrations at all breakdowns, repairs, calibration checks, opacity data, electronically to EPA’s traverse points. and zero and span adjustments. Central Data Exchange (CDX) by using (2) In conjunction with a performance * * * * * the Electronic Reporting Tool (ERT) (see test performed according to the (k) The procedures specified in http://www.epa.gov/ttn/chief/ert/ert requirements in paragraph (b)(1) of this paragraphs (k)(1) through (3) of this tool.html/) or other compatible section, the owner or operator of an section shall be used to determine gross electronic spreadsheet. Only data affected facility for which construction, energy output for sources demonstrating collected using test methods compatible reconstruction, or modification compliance with an output-based with ERT are subject to this requirement commenced after May 3, 2011, shall standard. to be submitted electronically into measure condensable PM using Method EPA’s WebFire database. 202 of appendix M of part 51. * * * * * (3) For an affected facility generating * * * * * (3) Method 9 of appendix A of this process steam in combination with ■ 20. Section 60.50Da is amended as part and the procedures in § 60.11 shall electrical generation, the gross energy follows: be used to determine opacity. output is determined according to the ■ a. By revising paragraph (b). * * * * * definition of ‘‘gross energy output’’ ■ b. By removing paragraph (g). ■ 21. Section 60.51Da is amended as ■ specified in § 60.41Da that is applicable c. By removing paragraph (h). follows: ■ to the affected facility. d. By removing paragraph (i). ■ a. By revising paragraph (a). ■ (l) The owner or operator of an § 60.50Da Compliance determination b. By revising paragraph (b)(5). ■ affected facility demonstrating procedures and methods. c. By revising paragraph (d). ■ d. By removing and reserving compliance with an output-based * * * * * standard shall install, certify, operate, (b) In conducting the performance paragraph (g). ■ and maintain a continuous flow tests to determine compliance with the e. By revising paragraph (k). monitoring system meeting the PM emissions limits in § 60.42Da, the § 60.51Da Reporting requirements. requirements of Performance owner or operator shall meet the (a) For SO , NO , PM, and NO plus Specification 6 of appendix B of this requirements specified in paragraphs 2 X X part and the calibration drift (CD) CO emissions, the performance test data (b)(1) through (3) of this section. from the initial and subsequent assessment, relative accuracy test audit (1) The owner or operator shall performance test and from the (RATA), and reporting provisions of measure filterable PM to determine performance evaluation of the procedure 1 of appendix F of this part, compliance with the applicable PM continuous monitors (including the and record the output of the system, for emissions limit in § 60.42Da as specified transmissometer) must be reported to measuring the volumetric flow rate of in paragraphs (b)(1)(i) through (ii) of this the Administrator. exhaust gases discharged to the section. atmosphere; or (i) The dry basis F factor (O ) (b) * * * 2 (5) Identification of the times when * * * * * procedures in Method 19 of appendix A (t) The owner or operator of an of this part shall be used to compute the emissions data have been excluded from affected facility demonstrating emission rate of PM. the calculation of average emission rates compliance with the output-based (ii) For the PM concentration, Method because of startup, shutdown, or emissions limitation under § 60.42Da 5 of appendix A of this part shall be malfunction. shall install, certify, operate, and used for an affected facility that does * * * * * maintain a CEMS for measuring PM not use a wet FGD. For an affected (d) In addition to the applicable emissions according to the requirements facility that uses a wet FGD, Method 5B requirements in § 60.7, the owner or of paragraph (v) of this section. An of appendix A of this part shall be used operator of an affected facility subject to owner or operator of an affected facility downstream of the wet FGD. the opacity limits in § 60.43c(c) and demonstrating compliance with the (A) The sampling time and sample conducting performance tests using input-based emissions limit in volume for each run shall be at least 120 Method 9 of appendix A–4 of this part § 60.42Da may install, certify, operate, minutes and 1.70 dscm (60 dscf). The shall submit excess emission reports for and maintain a CEMS for measuring PM probe and filter holder heating system any excess emissions from the affected emissions according to the requirements in the sampling train may be set to facility that occur during the reporting of paragraph (v) of this section. provide an average gas temperature of period and maintain records according (u) * * * no greater than 160 ± 14 °C (320 ± to the requirements specified in (1) * * * 25 °F). paragraph (d)(1) of this section. (iii) At a minimum, non-out-of-control (B) For each particulate run, the (1) For each performance test 1-hour CO emissions averages must be emission rate correction factor, conducted using Method 9 of appendix

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A–4 of this part, the owner or operator requirements of subpart KKKK of this (2) The steam generating unit or a shall keep the records including the part are not subject to this subpart. This replacement remains at a location for information specified in paragraphs subpart will continue to apply to all more than 180 consecutive days. Any (d)(1)(i) through (iii) of this section. other affected facilities (i.e. heat temporary boiler that replaces a (i) Dates and time intervals of all recovery steam generators with duct temporary boiler at a location and opacity observation periods; burners) that are capable of combusting performs the same or similar function (ii) Name, affiliation, and copy of more than 29 MW (100 MMBtu/h) heat will be included in calculating the current visible emission reading input of fossil fuel. If the affected consecutive time period. certification for each visible emission facility (i.e. heat recovery steam (3) The equipment is located at a observer participating in the generator) is subject to this subpart, only seasonal facility and operates during the performance test; and emissions resulting from combustion of full annual operating period of the (iii) Copies of all visible emission fuels in the steam generating unit are seasonal facility, remains at the facility observer opacity field data sheets. subject to this subpart. (The stationary for at least 2 years, and operates at that (2) [Reserved] combustion turbine emissions are facility for at least 3 months each year. * * * * * subject to subpart GG or KKKK, as (4) The equipment is moved from one (k) The owner or operator of an applicable, of this part.) location to another in an attempt to affected facility may submit electronic * * * * * circumvent the residence time quarterly reports for SO2 and/or NOX (l) Affected facilities that also meet requirements of this definition. and/or opacity in lieu of submitting the the applicability requirements under * * * * * written reports required under subpart BB of this part (Standards of ■ 25. Section 60.43b is amended by paragraphs (b) and (i) of this section. Performance for Kraft Pulp Mills) are revising paragraph (f) to read as follows: The format of each quarterly electronic subject to the SO2 and NOX standards under this subpart and the PM § 60.43b Standard for particulate matter report shall be coordinated with the (PM). permitting authority. The electronic standards under subpart BB. report(s) shall be submitted no later (m) Temporary boilers are not subject * * * * * than 30 days after the end of the to this subpart. (f) On and after the date on which the calendar quarter and shall be 24. Section 60.41b is amended by initial performance test is completed or accompanied by a certification revising the definition of ‘‘distillate oil’’, is required to be completed under statement from the owner or operator, and adding the definition of ‘‘temporary § 60.8, whichever date comes first, no boiler’’ in alphabetical order to read as indicating whether compliance with the owner or operator of an affected facility follows: applicable emission standards and that combusts coal, oil, wood, or mixtures of these fuels with any other minimum data requirements of this § 60.41b Definitions. fuels shall cause to be discharged into subpart was achieved during the * * * * * reporting period. the atmosphere any gases that exhibit Distillate oil means fuel oils that greater than 20 percent opacity (6- § 60.52Da [Amended] contain 0.05 weight percent nitrogen or minute average), except for one 6- less and comply with the specifications ■ minute period per hour of not more than 22. Section 60.52Da is amended by for fuel oil numbers 1 and 2, as defined removing and reserving paragraph (a). 27 percent opacity. An owner or by the American Society of Testing and operator of an affected facility that Subpart Db—[Amended] Materials in ASTM D396 (incorporated elects to install, calibrate, maintain, and by reference, see § 60.17), diesel fuel oil operate a continuous emissions ■ 23. Section 60.40b is amended as numbers 1 and 2, as defined by the monitoring system (CEMS) for follows: American Society for Testing and measuring PM emissions according to ■ a. By revising paragraph (c). Materials in ASTM D975 (incorporated the requirements of this subpart and is ■ b. By revising paragraph (h). by reference, see § 60.17), kerosine, as subject to a federally enforceable PM ■ c. By revising paragraph (i). defined by the American Society of limit of 0.030 lb/MMBtu or less is ■ Testing and Materials in ASTM D3699 d. By adding paragraph (1). exempt from the opacity standard ■ (incorporated by reference, see § 60.17), e. By adding paragraph (m). specified in this paragraph. biodiesel as defined by the American § 60.40b Applicability and delegation of Society of Testing and Materials in * * * * * ■ authority. ASTM D6751 (incorporated by 26. Section 60.44b is amended as * * * * * reference, see § 60.17), or biodiesel follows: (c) Affected facilities that also meet ■ a. The section heading is revised. blends as defined by the American ■ the applicability requirements under Society of Testing and Materials in b. By revising paragraph (b) subpart J or subpart Ja of this part are ASTM D7467 (incorporated by introductory text. ■ c. By revising paragraph (c). subject to the PM and NOX standards reference, see § 60.17). ■ under this subpart and the SO d. By revising paragraph (d). 2 * * * * * ■ standards under subpart J or subpart Ja e. By revising paragraph (e). Temporary boiler means any gaseous ■ f. By revising paragraph (l)(1). of this part, as applicable. or liquid fuel-fired steam generating * * * * * unit that is designed to, and is capable § 60.44b Standard for nitrogen oxides (h) Any affected facility that meets the of, being carried or moved from one (NOX). applicability requirements and is location to another by means of, for * * * * * subject to subpart Ea, subpart Eb, example, wheels, skids, carrying (b) Except as provided under subpart AAAA, or subpart CCCC of this handles, dollies, trailers, or platforms. A paragraphs (k) and (l) of this section, on part is not subject to this subpart. steam generating unit is not a temporary and after the date on which the initial (i) Affected facilities (i.e., heat boiler if any one of the following performance test is completed or is recovery steam generators) that are conditions exists: required to be completed under § 60.8, associated with stationary combustion (1) The equipment is attached to a whichever date comes first, no owner or turbines and that meet the applicability foundation. operator of an affected facility that

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simultaneously combusts mixtures of determined by the following formula calibrate, maintain, and operate a only coal, oil, or natural gas shall cause unless the affected facility has an continuous opacity monitoring systems to be discharged into the atmosphere annual capacity factor for coal, oil, and (COMS) for measuring the opacity of from that affected facility any gases that natural gas of 10 percent (0.10) or less emissions discharged to the atmosphere contain NOX in excess of a limit and is subject to a federally enforceable and record the output of the system. The determined by the use of the following requirement that limits operation of the owner or operator of an affected facility formula: affected facility to an annual capacity subject to an opacity standard under * * * * * factor of 10 percent (0.10) or less: § 60.43b and meeting the conditions (c) Except as provided under * * * * * under paragraphs (j)(1), (2), (3), (4), (5), paragraph (d) and (l) of this section, on (l) * * * or (6) of this section who elects not to and after the date on which the initial (1) 86 ng/J (0.20 lb/MMBtu) heat input use a COMS shall conduct a performance test is completed or is if the affected facility combusts coal, oil, performance test using Method 9 of required to be completed under § 60.8, or natural gas (or any combination of the appendix A–4 of this part and the whichever date comes first, no owner or three), alone or with any other fuels. procedures in § 60.11 to demonstrate operator of an affected facility that The affected facility is not subject to this compliance with the applicable limit in simultaneously combusts coal or oil, limit if it is subject to and in compliance § 60.43b by April 29, 2011, within 45 natural gas (or any combination of the with a federally enforceable requirement days of stopping use of an existing three), and wood, or any other fuel shall that limits operation of the facility to an COMS, or within 180 days after initial cause to be discharged into the annual capacity factor of 10 percent startup of the facility, whichever is later, atmosphere any gases that contain NOX (0.10) or less for coal, oil, and natural and shall comply with either paragraphs in excess of the emission limit for the gas (or any combination of the three); or (a)(1), (a)(2), or (a)(3) of this section. The coal, oil, natural gas (or any * * * * * observation period for Method 9 of combination of the three), combusted in ■ 27. Section 60.46b is amended by appendix A–4 of this part performance the affected facility, as determined revising paragraph (j)(14) to read as tests may be reduced from 3 hours to 60 pursuant to paragraph (a) or (b) of this follows: minutes if all 6-minute averages are less section. This standard does not apply to than 10 percent and all individual 15- an affected facility that is subject to and § 60.46b Compliance and performance test second observations are less than or in compliance with a federally methods and procedures for particulate equal to 20 percent during the initial 60 matter and nitrogen oxides. enforceable requirement that limits minutes of observation. operation of the affected facility to an * * * * * (1) * * * annual capacity factor of 10 percent (j) * * * (i) If no visible emissions are (0.10) or less for coal, oil, natural gas (or (14) As of January 1, 2012, and within observed, a subsequent Method 9 of any combination of the three). 90 days after the date of completing appendix A–4 of this part performance (d) On and after the date on which the each performance test, as defined in test must be completed within 12 initial performance test is completed or § 60.8, conducted to demonstrate calendar months from the date that the is required to be completed under compliance with this subpart, you must most recent performance test was § 60.8, whichever date comes first, no submit relative accuracy test audit (i.e., conducted or within 45 days of the next owner or operator of an affected facility reference method) data and performance day that fuel with an opacity standard that simultaneously combusts natural test (i.e., compliance test) data, except is combusted, whichever is later; gas and/or distillate oil with a potential opacity data, electronically to EPA’s (ii) If visible emissions are observed Central Data Exchange (CDX) by using SO2 emissions rate of 26 ng/J (0.060 lb/ but the maximum 6-minute average MMBtu) or less with wood, municipal- the Electronic Reporting Tool (ERT) (see opacity is less than or equal to 5 http://www.epa.gov/ttn/chief/ert/ percent, a subsequent Method 9 of type solid waste, or other solid fuel, _ except coal, shall cause to be discharged ert tool.html/) or other compatible appendix A–4 of this part performance into the atmosphere from that affected electronic spreadsheet. Only data test must be completed within 6 collected using test methods compatible facility any gases that contain NOX in calendar months from the date that the excess of 130 ng/J (0.30 lb/MMBtu) heat with ERT are subject to this requirement most recent performance test was input unless the affected facility has an to be submitted electronically into conducted or within 45 days of the next EPA’s WebFIRE database. day that fuel with an opacity standard annual capacity factor for natural gas, ■ distillate oil, or a mixture of these fuels 28. Section 60.48b is amended as is combusted, whichever is later; of 10 percent (0.10) or less and is subject follows: (iii) If the maximum 6-minute average ■ a. By revising paragraph (a) to a federally enforceable requirement opacity is greater than 5 percent but less introductory text. that limits operation of the affected than or equal to 10 percent, a ■ b. By revising paragraphs (a)(1)(i) facility to an annual capacity factor of subsequent Method 9 of appendix A–4 through (iii) . 10 percent (0.10) or less for natural gas, of this part performance test must be ■ c. By revising paragraph (a)(2)(ii). distillate oil, or a mixture of these fuels. completed within 3 calendar months ■ d. By revising paragraph (j) (e) Except as provided under from the date that the most recent introductory text. performance test was conducted or paragraph (l) of this section, on and after ■ e. By revising paragraph (j)(5). within 45 days of the next day that fuel the date on which the initial ■ f. By revising paragraph (j)(6). performance test is completed or is ■ with an opacity standard is combusted, g. By adding paragraph (j)(7). whichever is later; or required to be completed under § 60.8, ■ h. By adding paragraph (l). whichever date comes first, no owner or * * * * * operator of an affected facility that § 60.48b Emission monitoring for (2) * * * simultaneously combusts only coal, oil, particulate matter and nitrogen oxides. (ii) If no visible emissions are or natural gas with byproduct/waste (a) Except as provided in paragraph (j) observed for 10 operating days during shall cause to be discharged into the of this section, the owner or operator of which an opacity standard is applicable, atmosphere any gases that contain NOX an affected facility subject to the opacity observations can be reduced to once in excess of the emission limit standard under § 60.43b shall install, every 7 operating days during which an

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opacity standard is applicable. If any § 60.49b Reporting and recordkeeping recovery steam generators, fuel heaters, visible emissions are observed, daily requirements. and other affected facilities that are observations shall be resumed. * * * * * capable of combusting more than or * * * * * (r) * * * equal to 2.9 MW (10 MMBtu/h) heat (1) The owner or operator of an input of fossil fuel but less than or equal (j) The owner or operator of an affected facility who elects to to 29 MW (100 MMBtu/h) heat input of affected facility that meets the demonstrate that the affected facility fossil fuel. If the heat recovery steam conditions in either paragraph (j)(1), (2), combusts only very low sulfur oil, generator, fuel heater, or other affected (3), (4), (5), (6), or (7) of this section is natural gas, wood, a mixture of these facility is subject to this subpart, only not required to install or operate a fuels, or any of these fuels (or a mixture emissions resulting from combustion of COMS if: of these fuels) in combination with fuels in the steam generating unit are * * * * * other fuels that are known to contain an subject to this subpart. (The stationary (5) The affected facility uses a bag insignificant amount of sulfur in combustion turbine emissions are leak detection system to monitor the § 60.42b(j) or § 60.42b(k) shall obtain subject to subpart GG or KKKK, as performance of a fabric filter (baghouse) and maintain at the affected facility fuel applicable, of this part.) according to the most current receipts (such as a current, valid (f) Any affected facility that meets the requirements in section § 60.48Da of purchase contract, tariff sheet, or applicability requirements of and is this part; or transportation contract) from the fuel subject to subpart AAAA or subpart (6) The affected facility uses an ESP supplier that certify that the oil meets CCCC of this part is not subject to this as the primary PM control device and the definition of distillate oil and subpart. uses an ESP predictive model to gaseous fuel meets the definition of (g) Any facility that meets the monitor the performance of the ESP natural gas as defined in § 60.41b and applicability requirements and is developed in accordance and operated the applicable sulfur limit. For the subject to an EPA approved State or according to the most current purposes of this section, the distillate Federal section 111(d)/129 plan requirements in section § 60.48Da of oil need not meet the fuel nitrogen implementing subpart BBBB of this part this part; or content specification in the definition of is not subject to this subpart. distillate oil. Reports shall be submitted (h) Affected facilities that also meet (7) The affected facility burns only to the Administrator certifying that only the applicability requirements under gaseous fuels or fuel oils that contain very low sulfur oil meeting this subpart J or subpart Ja of this part are less than or equal to 0.30 weight percent definition, natural gas, wood, and/or subject to the PM and NOX standards sulfur and operates according to a other fuels that are known to contain under this subpart and the SO2 written site-specific monitoring plan insignificant amounts of sulfur were standards under subpart J or subpart Ja approved by the permitting authority. combusted in the affected facility during of this part, as applicable. This monitoring plan must include the reporting period; or (i) Temporary boilers are not subject procedures and criteria for establishing to this subpart. and monitoring specific parameters for * * * * * ■ 31. Section 60.41c is amended as the affected facility indicative of Subpart Dc—[Amended] follows: compliance with the opacity standard. ■ a. By removing the definition of * * * * * ■ 30. Section 60.40c is amended as ‘‘Cogeneration.’’ ■ b. By revising the definition of (l) An owner or operator of an affected follows: ■ a. By revising paragraph (a). ‘‘Distillate oil.’’ facility that is subject to an opacity ■ b. By revising paragraph (e). ■ c. By adding a definition of standard under § 60.43b(f) is not ■ c. By revising paragraph (f). ‘‘Temporary boiler’’ in alphabetical required to operate a COMS provided ■ d. By revising paragraph (g). order. that the unit burns only gaseous fuels ■ e. By adding paragraph (h). and/or liquid fuels (excluding residue ■ f. By adding paragraph (i). § 60.41c Definitions. oil) with a potential SO2 emissions rate * * * * * no greater than 26 ng/J (0.060 lb/ § 60.40c Applicability and delegation of Distillate oil means fuel oil that MMBtu), and the unit operates authority. complies with the specifications for fuel according to a written site-specific (a) Except as provided in paragraphs oil numbers 1 or 2, as defined by the monitoring plan approved by the (d), (e), (f), and (g) of this section, the American Society for Testing and permitting authority is not required to affected facility to which this subpart Materials in ASTM D396 (incorporated operate a COMS. This monitoring plan applies is each steam generating unit for by reference, see § 60.17), diesel fuel oil must include procedures and criteria for which construction, modification, or numbers 1 or 2, as defined by the establishing and monitoring specific reconstruction is commenced after June American Society for Testing and parameters for the affected facility 9, 1989 and that has a maximum design Materials in ASTM D975 (incorporated indicative of compliance with the heat input capacity of 29 megawatts by reference, see § 60.17), kerosine, as opacity standard. For testing performed (MW) (100 million British thermal units defined by the American Society of as part of this site-specific monitoring per hour (MMBtu/h)) or less, but greater Testing and Materials in ASTM D3699 plan, the permitting authority may than or equal to 2.9 MW (10 MMBtu/h). (incorporated by reference, see § 60.17), require as an alternative to the * * * * * biodiesel as defined by the American notification and reporting requirements (e) Affected facilities (i.e. heat Society of Testing and Materials in specified in §§ 60.8 and 60.11 that the recovery steam generators and fuel ASTM D6751 (incorporated by owner or operator submit any deviations heaters) that are associated with reference, see § 60.17), or biodiesel with the excess emissions report stationary combustion turbines and blends as defined by the American required under § 60.49b(h). meet the applicability requirements of Society of Testing and Materials in ■ 29. Section 60.49b is amended by subpart KKKK of this part are not ASTM D7467 (incorporated by revising paragraph (r)(1) to read as subject to this subpart. This subpart will reference, see § 60.17). follows. continue to apply to all other heat * * * * *

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Temporary boiler means a steam sulfur. The percent reduction contain PM in excess of the following generating unit that combusts natural requirements are not applicable to emissions limits: gas or distillate oil with a potential SO2 affected facilities under this paragraph. * * * * * emissions rate no greater than 26 ng/J (e) * * * (c) On and after the date on which the (0.060 lb/MMBtu), and the unit is (1) * * * initial performance test is completed or designed to, and is capable of, being (ii) Has a heat input capacity greater required to be completed under § 60.8, carried or moved from one location to than 22 MW (75 MMBtu/h); and whichever date comes first, no owner or another by means of, for example, operator of an affected facility that * * * * * wheels, skids, carrying handles, dollies, combusts coal, wood, or oil and has a trailers, or platforms. A steam (h) For affected facilities listed under heat input capacity of 8.7 MW (30 generating unit is not a temporary boiler paragraphs (h)(1), (2), (3), or (4) of this MMBtu/h) or greater shall cause to be if any one of the following conditions section, compliance with the emission discharged into the atmosphere from exists: limits or fuel oil sulfur limits under this that affected facility any gases that (1) The equipment is attached to a section may be determined based on a exhibit greater than 20 percent opacity foundation. certification from the fuel supplier, as (6-minute average), except for one 6- (2) The steam generating unit or a described under § 60.48c(f), as minute period per hour of not more than replacement remains at a location for applicable. 27 percent opacity. Owners and more than 180 consecutive days. Any * * * * * operators of an affected facility that temporary boiler that replaces a (3) Coal-fired affected facilities with elect to install, calibrate, maintain, and temporary boiler at a location and heat input capacities between 2.9 and operate a continuous emissions performs the same or similar function 8.7 MW (10 and 30 MMBtu/h). monitoring system (CEMS) for will be included in calculating the (4) Other fuels-fired affected facilities measuring PM emissions according to consecutive time period. with heat input capacities between 2.9 the requirements of this subpart and are (3) The equipment is located at a and 8.7 MW (10 and 30 MMBtu/h). subject to a federally enforceable PM seasonal facility and operates during the * * * * * limit of 0.030 lb/MMBtu or less are full annual operating period of the ■ exempt from the opacity standard seasonal facility, remains at the facility 33. Section 60.43c is amended as specified in this paragraph (c). for at least 2 years, and operates at that follows: ■ * * * * * facility for at least 3 months each year. a. By revising paragraph (a) (e)(1) On and after the date on which (4) The equipment is moved from one introductory text. the initial performance test is completed location to another in an attempt to ■ b. By revising paragraph (b) or is required to be completed under circumvent the residence time introductory text. § 60.8, whichever date comes first, no requirements of this definition. ■ c. By revising paragraph (c). owner or operator of an affected facility * * * * * ■ d. By revising paragraphs (e)(1), (3), that commences construction, ■ 32. Section 60.42c is amended as and (4). reconstruction, or modification after follows: February 28, 2005, and that combusts ■ a. By revising paragraph (c)(1) and (3). § 60.43c Standard for particulate matter (PM). coal, oil, wood, a mixture of these fuels, ■ b. By revising paragraph (d). or a mixture of these fuels with any ■ c. By revising paragraph (e)(1)(ii). (a) On and after the date on which the other fuels and has a heat input capacity ■ d. By revising paragraph (h) initial performance test is completed or of 8.7 MW (30 MMBtu/h) or greater introductory text. required to be completed under § 60.8, shall cause to be discharged into the ■ e. By revising paragraph (h)(3). whichever date comes first, no owner or atmosphere from that affected facility ■ f. By adding paragraph (h)(4). operator of an affected facility that any gases that contain PM in excess of commenced construction, 13 ng/J (0.030 lb/MMBtu) heat input, § 60.42c Standard for sulfur dioxide (SO ). 2 reconstruction, or modification on or except as provided in paragraphs (e)(2), * * * * * before February 28, 2005, that combusts (e)(3), and (e)(4) of this section. (c) * * * coal or combusts mixtures of coal with * * * * * (1) Affected facilities that have a heat other fuels and has a heat input capacity (3) On and after the date on which the input capacity of 22 MW (75 MMBtu/h) of 8.7 MW (30 MMBtu/h) or greater, initial performance test is completed or or less; shall cause to be discharged into the is required to be completed under * * * * * atmosphere from that affected facility § 60.8, whichever date comes first, no (3) Affected facilities located in a any gases that contain PM in excess of owner or operator of an affected facility noncontinental area; or the following emission limits: that commences modification after * * * * * * * * * * February 28, 2005, and that combusts (d) On and after the date on which the (b) On and after the date on which the over 30 percent wood (by heat input) on initial performance test is completed or initial performance test is completed or an annual basis and has a heat input required to be completed under § 60.8, required to be completed under § 60.8, capacity of 8.7 MW (30 MMBtu/h) or whichever date comes first, no owner or whichever date comes first, no owner or greater shall cause to be discharged into operator of an affected facility that operator of an affected facility that the atmosphere from that affected combusts oil shall cause to be commenced construction, facility any gases that contain PM in discharged into the atmosphere from reconstruction, or modification on or excess of 43 ng/J (0.10 lb/MMBtu) heat that affected facility any gases that before February 28, 2005, that combusts input. contain SO2 in excess of 215 ng/J (0.50 wood or combusts mixtures of wood (4) An owner or operator of an lb/MMBtu) heat input from oil; or, as an with other fuels (except coal) and has a affected facility that commences alternative, no owner or operator of an heat input capacity of 8.7 MW (30 construction, reconstruction, or affected facility that combusts oil shall MMBtu/h) or greater, shall cause to be modification after February 28, 2005, combust oil in the affected facility that discharged into the atmosphere from and that combusts only oil that contains contains greater than 0.5 weight percent that affected facility any gases that no more than 0.50 weight percent sulfur

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or a mixture of 0.50 weight percent subject to an opacity standard in standard in § 60.43c(c) is not required to sulfur oil with other fuels not subject to § 60.43c(c) that is not required to use a operate a COMS provided that the a PM standard under § 60.43c and not COMS due to paragraphs (c), (d), (e), or affected facility meets the conditions in using a post-combustion technology (f) of this section that elects not to use either paragraphs (f)(1), (2), or (3) of this (except a wet scrubber) to reduce PM or a COMS shall conduct a performance section. SO2 emissions is not subject to the PM test using Method 9 of appendix A–4 of (1) The affected facility uses a fabric limit in this section. this part and the procedures in § 60.11 filter (baghouse) as the primary PM ■ 34. Section 60.45c is amended as to demonstrate compliance with the control device and, the owner or follows: applicable limit in § 60.43c by April 29, operator operates a bag leak detection ■ a. By revising paragraph (c)(14). 2011, within 45 days of stopping use of system to monitor the performance of ■ b. By revising paragraph (d). an existing COMS, or within 180 days the fabric filter according to the after initial startup of the facility, requirements in section § 60.48Da of § 60.45c Compliance and performance test whichever is later, and shall comply this part. methods and procedures for particulate with either paragraphs (a)(1), (a)(2), or (2) The affected facility uses an ESP matter. (a)(3) of this section. The observation as the primary PM control device, and * * * * * period for Method 9 of appendix A–4 of the owner or operator uses an ESP (c) * * * this part performance tests may be predictive model to monitor the (14) As of January 1, 2012, and within reduced from 3 hours to 60 minutes if performance of the ESP developed in 90 days after the date of completing all 6-minute averages are less than 10 accordance and operated according to each performance test, as defined in percent and all individual 15-second the requirements in section § 60.48Da of § 60.8, conducted to demonstrate observations are less than or equal to 20 this part. compliance with this subpart, you must percent during the initial 60 minutes of (3) The affected facility burns only submit relative accuracy test audit (i.e., observation. gaseous fuels and/or fuel oils that reference method) data and performance (1) * * * contain no greater than 0.5 weight test (i.e., compliance test) data, except (i) If no visible emissions are percent sulfur, and the owner or opacity data, electronically to EPA’s observed, a subsequent Method 9 of operator operates the unit according to Central Data Exchange (CDX) by using appendix A–4 of this part performance a written site-specific monitoring plan the Electronic Reporting Tool (ERT) (see test must be completed within 12 approved by the permitting authority. http://www.epa.gov/ttn/chief/ert/ert calendar months from the date that the This monitoring plan must include tool.html/) or other compatible most recent performance test was procedures and criteria for establishing electronic spreadsheet. Only data conducted or within 45 days of the next and monitoring specific parameters for collected using test methods compatible day that fuel with an opacity standard the affected facility indicative of with ERT are subject to this requirement is combusted, whichever is later; compliance with the opacity standard. to be submitted electronically into (ii) If visible emissions are observed For testing performed as part of this site- EPA’s WebFIRE database. but the maximum 6-minute average specific monitoring plan, the permitting (d) The owner or operator of an opacity is less than or equal to 5 authority may require as an alternative affected facility seeking to demonstrate percent, a subsequent Method 9 of to the notification and reporting compliance under § 60.43c(e)(4) shall appendix A–4 of this part performance requirements specified in §§ 60.8 and follow the applicable procedures under test must be completed within 6 60.11 that the owner or operator submit § 60.48c(f). For residual oil-fired calendar months from the date that the any deviations with the excess affected facilities, fuel supplier most recent performance test was emissions report required under certifications are only allowed for conducted or within 45 days of the next § 60.48c(c). facilities with heat input capacities day that fuel with an opacity standard between 2.9 and 8.7 MW (10 to 30 is combusted, whichever is later; Subpart HHHH—[Removed and MMBtu/h). (iii) If the maximum 6-minute average Reserved] ■ 35. Section 60.47c is amended as opacity is greater than 5 percent but less ■ follows: 36. Subpart HHHH is removed and than or equal to 10 percent, a reserved. ■ a. By revising paragraph (a) subsequent Method 9 of appendix A–4 introductory text. of this part performance test must be PART 63—[AMENDED] ■ b. By revising paragraphs (a)(1)(i) completed within 3 calendar months through (iii). from the date that the most recent ■ 37. The authority citation for 40 CFR ■ c. By revising paragraph (a)(2)(ii). performance test was conducted or Part 63 continues to read as follows: ■ d. By revising paragraph (f). within 45 days of the next day that fuel ■ Authority: 42 U.S.C. 7401, et seq. e. By removing paragraph (g). with an opacity standard is combusted, § 60.47c Emission monitoring for whichever is later; or Subpart A—[Amended] particulate matter. * * * * * ■ 38. Section 63.14 is amended as (a) Except as provided in paragraphs (2) * * * (ii) If no visible emissions are follows: (c), (d), (e), and (f) of this section, the ■ a. By adding paragraphs (b)(19) and owner or operator of an affected facility observed for 10 operating days during which an opacity standard is applicable, (20). combusting coal, oil, or wood that is ■ b. By adding paragraphs (b)(22) and subject to the opacity standards under observations can be reduced to once every 7 operating days during which an (23). § 60.43c shall install, calibrate, ■ c. By adding paragraphs (b)(69) opacity standard is applicable. If any maintain, and operate a continuous through (72). opacity monitoring system (COMS) for visible emissions are observed, daily ■ d. By revising paragraph (i)(1). measuring the opacity of the emissions observations shall be resumed. discharged to the atmosphere and * * * * * § 63.14 Incorporation by reference. record the output of the system. The (f) An owner or operator of an affected * * * * * owner or operator of an affected facility facility that is subject to an opacity (b) * * *

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(19) ASTM D95–05 (Reapproved 63.9307(c)(2), 63.9323(a)(3), 63.10022 How do I demonstrate continuous 2010), Standard Test Method for Water 63.11148(e)(3)(iii), 63.11155(e)(3), compliance under the emissions in Petroleum Products and Bituminous 63.11162(f)(3)(iii) and (f)(4), averaging provision? Materials by Distillation, approved May 63.11163(g)(1)(iii) and (g)(2), 63.10023 How do I establish my PM CPMS operating limit and determine 1, 2010, IBR approved for 63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), compliance with it? § 63.10005(i)(4)(i). table 5 to subpart DDDDD of this part, (20) ASTM Method D388–05, table 1 to subpart ZZZZZ of this part, Notifications, Reports, and Records Standard Classification of Coals by table 4 to subpart JJJJJJ of this part, and 63.10030 What notifications must I submit Rank, approved September 15, 2005, table 5 to subpart UUUUU of this part. and when? IBR approved for § 63.10042. 63.10031 What reports must I submit and * * * * * when? * * * * * ■ 63.10032 What records must I keep? (22) ASTM Method D396–10, 39. Part 63 is amended by adding subpart UUUUU to read as follows: 63.10033 In what form and how long must Standard Specification for Fuel Oils, I keep my records? including Appendix X1, approved Subpart UUUUU—National Emission Other Requirements and Information October 1, 2010, IBR approved for Standards for Hazardous Air § 63.10042. 63.10040 What parts of the General Pollutants: Coal- and Oil-Fired Electric Provisions apply to me? (23) ASTM D4006–11, Standard Test Utility Steam Generating Units Method for Water in Crude Oil by 63.10041 Who implements and enforces this subpart? Distillation, including Annex A1 and Sec. 63.10042 What definitions apply to this Appendix X1, approved June 1, 2011, What This Subpart Covers subpart? IBR approved for § 63.10005(i)(4)(ii). 63.9980 What is the purpose of this Tables to Subpart UUUUU of Part 63 * * * * * subpart? Table 1 to Subpart UUUUU of Part 63— (69) ASTM D4057–06 (Reapproved 63.9981 Am I subject to this subpart? 2011), Standard Practice for Manual Emission Limits for New or 63.9982 What is the affected source of this Reconstructed EGUs Sampling of Petroleum and Petroleum subpart? Table 2 to Subpart UUUUU of Part 63— Products, including Annex A1, 63.9983 Are any EGUs not subject to this Emission Limits for Existing EGUs approved June 1, 2011, IBR approved for subpart? Table 3 to Subpart UUUUU of Part 63—Work § 63.10005(i)(4)(iv). 63.9984 When do I have to comply with Practice Standards (70) ASTM D4177–95 (Reapproved this subpart? Table 4 to Subpart UUUUU of Part 63— 2010), Standard Practice for Automatic 63.9985 What is a new EGU? Operating Limits for EGUs Table 5 to Subpart UUUUU of Part 63— Sampling of Petroleum and Petroleum Emission Limitations and Work Practice Performance Testing Requirements Products, including Annexes A1 Standards Table 6 to Subpart UUUUU of Part 63— through A6 and Appendices X1 and X2, 63.9990 What are the subcategories of Establishing PM CPMS Operating Limits approved May 1, 2010, IBR approved for EGUs? Table 7 to Subpart UUUUU of Part 63— § 63.10005(i)(4)(iii). 63.9991 What emission limitations, work Demonstrating Continuous Compliance (71) ASTM D6348–03 (Reapproved practice standards, and operating limits Table 8 to Subpart UUUUU of Part 63— 2010), Standard Test Method for must I meet? Reporting Requirements Determination of Gaseous Compounds General Compliance Requirements Table 9 to Subpart UUUUU of Part 63— by Extractive Direct Interface Fourier Applicability of General Provisions to 63.10000 What are my general requirements Transform Infrared (FTIR) Spectroscopy, Subpart UUUUU for complying with this subpart? Appendix A to Subpart UUUUU—Hg including Annexes A1 through A8, 63.10001 Affirmative defense for approved October 1, 2010, IBR approved Monitoring Provisions exceedence of emission limit during Appendix B to Subpart UUUUU—HCl and for table 1 to subpart UUUUU of this malfunction. HF Monitoring Provisions part, table 2 to subpart UUUUU of this Testing and Initial Compliance part, table 5 to subpart UUUUU of this Requirements Subpart UUUUU—National Emission part, and appendix B to subpart Standards for Hazardous Air UUUUU of this part. 63.10005 What are my initial compliance requirements and by what date must I Pollutants: Coal- and Oil-Fired Electric (72) ASTM D6784–02 (Reapproved conduct them? Utility Steam Generating Units 2008), Standard Test Method for 63.10006 When must I conduct subsequent What This Subpart Covers Elemental, Oxidized, Particle-Bound performance tests or tune-ups? and Total Mercury in Flue Gas 63.10007 What methods and other § 63.9980 What is the purpose of this Generated from Coal-Fired Stationary procedures must I use for the subpart? performance tests? Sources (Ontario Hydro Method), This subpart establishes national approved April 1, 2008, IBR approved 63.10008 [Reserved] 63.10009 May I use emissions averaging to emission limitations and work practice for table 5 to subpart UUUUU of this standards for hazardous air pollutants part, and appendix A to subpart comply with this subpart? 63.10010 What are my monitoring, (HAP) emitted from coal- and oil-fired UUUUU of this part. installation, operation, and maintenance electric utility steam generating units * * * * * requirements? (EGUs) as defined in § 63.10042 of this (i) * * * 63.10011 How do I demonstrate initial subpart. This subpart also establishes (1) ANSI/ASME PTC 19.10–1981, compliance with the emission requirements to demonstrate initial and ‘‘Flue and Exhaust Gas Analyses [part limitations and work practice standards? continuous compliance with the 10, Instruments and Apparatus],’’ IBR Continuous Compliance Requirements emission limitations. approved for §§ 63.309(k)(1)(iii), 63.10020 How do I monitor and collect data § 63.9981 Am I subject to this subpart? 63.865(b), 63.3166(a)(3), to demonstrate continuous compliance? 63.3360(e)(1)(iii), 63.3545(a)(3), 63.10021 How do I demonstrate continuous You are subject to this subpart if you 63.3555(a)(3), 63.4166(a)(3), compliance with the emission own or operate a coal-fired EGU or an 63.4362(a)(3), 63.4766(a)(3), limitations, operating limits, and work oil-fired EGU as defined in § 63.10042 of 63.4965(a)(3), 63.5160(d)(1)(iii), practice standards? this subpart.

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§ 63.9982 What is the affected source of internal combustion engines, and Emission Limitations and Work this subpart? industrial boilers). Practice Standards (a) This subpart applies to each (d) Any electric steam generating unit individual or group of two or more new, § 63.9990 What are the subcategories of combusting solid waste is a solid waste EGUs? reconstructed, and existing affected incineration unit subject to standards source(s) as described in paragraphs established under sections 129 and 111 (a) Coal-fired EGUs are subcategorized (a)(1) and (2) of this section within a of the Clean Air Act. as defined in paragraphs (a)(1) through contiguous area and under common (a)(2) of this section and as defined in control. § 63.9984 When do I have to comply with § 63.10042. (1) The affected source of this subpart this subpart? (1) EGUs designed for coal with a is the collection of all existing coal- or (a) If you have a new or reconstructed heating value greater than or equal to oil-fired EGUs, as defined in 63.10042, EGU, you must comply with this 8,300 Btu/lb, and within a subcategory. subpart by April 16, 2012 or upon (2) EGUs designed for low rank virgin (2) The affected source of this subpart startup of your EGU, whichever is later, coal. is each new or reconstructed coal- or and as further provided for in (b) Oil-fired EGUs are subcategorized oil-fired EGU as defined in 63.10042. § 63.10005(g). as noted in paragraphs (b)(1) through (b) An EGU is new if you commence (b) If you have an existing EGU, you (b)(4) of this section and as defined in construction of the coal- or oil-fired § 63.10042. EGU after May 3, 2011, and you meet must comply with this subpart no later (1) Continental liquid oil-fired EGUs the applicability criteria at the time you than April 16, 2015. commence construction. (c) You must meet the notification (2) Non-continental liquid oil-fired (c) An EGU is reconstructed if you requirements in § 63.10030 according to EGUs, meet the reconstruction criteria as the schedule in § 63.10030 and in (3) Limited-use liquid oil-fired EGUs, defined in § 63.2, you commence subpart A of this part. Some of the and reconstruction after May 3, 2011, and notifications must be submitted before (4) EGUs designed to burn solid oil- you meet the applicability criteria at the you are required to comply with the derived fuel. time you commence reconstruction. emission limits and work practice (c) IGCC units combusting either (d) An EGU is existing if it is not new standards in this subpart. gasified coal or gasified solid oil-derived or reconstructed. An existing electric (d) An electric steam generating unit fuel. For purposes of compliance, steam generating unit that meets the that does not meet the definition of an monitoring, recordkeeping, and applicability requirements after the EGU subject to this subpart on April 16, reporting requirements in this subpart, effective date of this final rule due to a 2012 for new sources or April 16, 2015 IGCC units are subject in the same change process (e.g., fuel or utilization) for existing sources must comply with manner as coal-fired units and solid oil- is considered to be an existing source the applicable existing source derived fuel-fired units, unless under this subpart. provisions of this subpart on the date otherwise indicated. § 63.9983 Are any EGUs not subject to this such unit meets the definition of an § 63.9991 What emission limitations, work subpart? EGU subject to this subpart. practice standards, and operating limits The types of electric steam generating (e) If you own or operate an electric must I meet? units listed in paragraphs (a) through (d) steam generating unit that is exempted (a) You must meet the requirements in of this section are not subject to this from this subpart under § 63.9983(d), if paragraphs (a)(1) and (2) of this section. subpart. the manner of operating the unit You must meet these requirements at all (a) Any unit designated as a stationary changes such that the combustion of times. combustion turbine, other than an waste is discontinued and the unit (1) You must meet each emission integrated gasification combined cycle becomes a coal-fired or oil-fired EGU (as limit and work practice standard in (IGCC) unit, covered by 40 CFR part 63, defined in § 63.10042), you must be in Table 1 through 3 to this subpart that subpart YYYY. compliance with this subpart on April applies to your EGU, for each EGU at (b) Any electric utility steam 16, 2015 or on the effective date of the your source, except as provided under generating unit that is not a coal- or oil- switch from waste combustion to coal or § 63.10009. fired EGU and combusts natural gas for oil combustion, whichever is later. (2) You must meet each operating more than 10.0 percent of the average (f) You must demonstrate that limit in Table 4 to this subpart that annual heat input during any 3 calendar compliance has been achieved, by applies to your EGU. years or for more than 15.0 percent of conducting the required performance the annual heat input during any (b) As provided in § 63.6(g), the tests and other activities, no later than Administrator may approve use of an calendar year. 180 days after the applicable date in (c) Any electric utility steam alternative to the work practice paragraph (a), (b), (c), (d), or (e) of this standards in this section. generating unit that has the capability of section. combusting more than 25 MW of coal or (c) You may use the alternate SO2 oil but did not fire coal or oil for more § 63.9985 What is a new EGU? limit in Tables 1 and 2 to this subpart only if your coal-fired EGU: than 10.0 percent of the average annual (a) A new EGU is an EGU that meets heat input during any 3 calendar years any of the criteria specified in paragraph (1) Has a system using wet or dry flue or for more than 15.0 percent of the (a)(1) through (a)(2) of this section. gas desulfurization technology and SO2 annual heat input during any calendar continuous emissions monitoring (1) An EGU that commenced year. Heat input means heat derived system (CEMS) installed on the unit; construction after May 3, 2011. from combustion of fuel in an EGU and and does not include the heat derived from (2) An EGU that commenced (2) At all times, you operate the wet preheated combustion air, recirculated reconstruction or modification after May or dry flue gas desulfurization flue gases or exhaust gases from other 3, 2011. technology installed on the unit sources (such as stationary gas turbines, (b) [Reserved] consistent with § 63.10000(b).

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General Compliance Requirements mercury HAP metals, or filterable (i) For an existing liquid oil-fired unit, particulate matter (PM), you must you may conduct the performance § 63.10000 What are my general demonstrate compliance through an testing in accordance with requirements for complying with this subpart? initial performance test and you must § 63.10005(h), to determine whether the monitor continuous performance unit qualifies as a LEE for one or more (a) You must be in compliance with through either use of a particulate pollutants. For a qualifying LEE for Hg the emission limits and operating limits matter continuous parametric emissions limits, you must conduct a in this subpart. These limits apply to monitoring system (PM CPMS), a PM 30-day performance test using Method you at all times except during periods CEMS, or compliance performance 30B at least once every 12 calendar of startup and shutdown; however, for testing repeated quarterly. months to demonstrate continued LEE coal-fired, liquid oil-fired, or solid oil- (A) If you elect to use PM CPMS, you status. For a qualifying LEE of any other derived fuel-fired EGUs, you are will establish a site-specific operating applicable emissions limits, you must required to meet the work practice limit corresponding to the results of the conduct a performance test at least once requirements in Table 3 to this subpart performance test demonstrating every 36 calendar months to during periods of startup or shutdown. compliance with the pollutant with demonstrate continued LEE status. (b) At all times you must operate and which you choose to comply: total non- (ii) If your existing liquid oil-fired maintain any affected source, including mercury HAP metals, individual non- unit does not qualify as a LEE for total associated air pollution control mercury HAP metals or filterable PM. HAP metals (including mercury), equipment and monitoring equipment, You will use the PM CPMS to individual metals (including mercury), in a manner consistent with safety and demonstrate continuous compliance or filterable PM you must demonstrate good air pollution control practices for with this operating limit. If you elect to compliance through an initial minimizing emissions. Determination of use a PM CPMS, you must repeat the performance test and you must monitor whether such operation and performance test annually for the continuous performance through either maintenance procedures are being used selected pollutant limit and reassess and use of a PM CPMS, a PM CEMS, or will be based on information available adjust the site-specific operating limit in performance testing conducted to the EPA Administrator which may accordance with the results of the quarterly. include, but is not limited to, performance test. (A) If you elect to use PM CPMS, you monitoring results, review of operation will establish a site-specific operating (B) You may also opt to install and and maintenance procedures, review of limit corresponding to the results of the operate a particulate matter CEMS operation and maintenance records, and performance test demonstrating certified in accordance with inspection of the source. compliance with the pollutant with Performance Specification 11 and (c)(1) For coal-fired units and solid which you choose to comply: total HAP Procedure 2 of 40 CFR part 60, oil-derived fuel-fired units, initial metals, individual HAP metals, or Appendices B and F, respectively, in performance testing is required for all filterable PM. You will use the PM pollutants, to demonstrate compliance accordance with § 63.10010(i). CPMS to demonstrate continuous with the applicable emission limits. (v) If your coal-fired or solid oil- compliance with this operating limit. If (i) For a coal-fired or solid oil-derived derived fuel-fired EGU does not qualify you elect to use a PM CPMS, you must fuel-fired EGU or IGCC EGU, you may as a LEE for hydrogen chloride (HCl), repeat the performance test at least conduct the initial performance testing you may demonstrate initial and annually for the selected pollutant limit in accordance with § 63.10005(h), to continuous compliance through use of and reassess and adjust the site-specific determine whether the unit qualifies as an HCl CEMS, installed and operated in operating limit in accordance with the a low emitting EGU (LEE) for one or accordance with Appendix B to this results of the performance test. more applicable emissions limits, with subpart. As an alternative to HCl CEMS, (B) If you elect to use a PM CEMS, two exceptions: you may demonstrate initial and you will use the CEMS in accordance (A) You may not pursue the LEE continuous compliance by conducting with § 63.10010(i) to demonstrate initial option if your coal-fired, IGCC, or solid an initial and periodic quarterly and continuous compliance with the oil-derived fuel-fired EGU is equipped performance stack test for HCl. If your filterable PM emission limit. with an acid gas scrubber and has a EGU uses wet or dry flue gas (iii) If your existing liquid oil-fired main stack and bypass stack exhaust desulfurization technology (this unit does not qualify as a LEE for configuration, and includes limestone injection into a hydrogen chloride (HCl) or for hydrogen (B) You may not pursue the LEE fluidized bed combustion unit), you fluoride (HF), you may demonstrate option for Hg if your coal-fired, solid may apply a second alternative to HCl initial and continuous compliance oil-fired fuel fired EGU or IGCC EGU is CEMS by installing and operating a through use of an HCl CEMS, an HF new. sulfur dioxide (SO2) CEMS installed and CEMS, or an HCl and HF CEMS, (ii) For a qualifying LEE for Hg operated in accordance with part 75 of installed and operated in accordance emissions limits, you must conduct a this chapter to demonstrate compliance with Appendix B to this rule. As an 30-day performance test using Method with the applicable SO2 emissions limit. alternative to HCl CEMS, HF CEMS, or 30B at least once every 12 calendar (vi) If your coal-fired or solid oil- HCl and HF CEMS, you may months to demonstrate continued LEE derived fuel-fired EGU does not qualify demonstrate initial and continuous status. as a LEE for Hg, you must demonstrate compliance by conducting periodic (iii) For a qualifying LEE of any other initial and continuous compliance quarterly performance stack tests for applicable emissions limits, you must through use of a Hg CEMS or a sorbent HCl and HF. If you elect to demonstrate conduct a performance test at least once trap monitoring system, in accordance compliance through quarterly every 36 calendar months to with appendix A to this subpart. performance testing, then you must also demonstrate continued LEE status. (2) For liquid oil-fired EGUs, except develop a site-specific monitoring plan (iv) If your coal-fired or solid oil- limited use liquid oil-fired EGUs, initial to ensure that the operations of the unit derived fuel-fired EGU or IGCC EGU performance testing is required for all remain consistent with those during the does not qualify as a LEE for total non- pollutants, to demonstrate compliance performance test. As another alternative, mercury HAP metals, individual non- with the applicable emission limits. you may measure or obtain, and keep

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records of, fuel moisture content; as where the CMS has already undergone under CAA section 129 (e.g., 40 CFR long as fuel moisture does not exceed a performance evaluation that meets the part 60, subpart CCCC (New Source 1.0 percent by weight, you need not requirements of § 63.10010 (e.g., if the Performance Standards (NSPS) for conduct other HCl or HF monitoring or CMS was previously certified under Commercial and Industrial Solid Waste testing. another program). Incineration Units, or Subpart DDDD (iv) If your unit qualifies as a limited- (4) You must operate and maintain (Emissions Guidelines (EG) for Existing use liquid oil-fired as defined in the CMS according to the site-specific Commercial and Industrial Solid Waste § 63.10042, then you are not subject to monitoring plan. Incineration Units). Notwithstanding the emission limits in Tables 1 and 2, (5) The provisions of the site-specific the provisions of this subpart, an EGU but must comply with the performance monitoring plan must address the that starts combusting solid waste is tune-up work practice requirements in following items: immediately subject to standards under Table 3. (i) Installation of the CEMS or sorbent CAA section 129 and the EGU remains (d)(1) If you demonstrate compliance trap monitoring system sampling probe subject to those standards until the EGU with any applicable emissions limit or other interface at a measurement no longer meets the definition of a solid through use of a continuous monitoring location relative to each affected process waste incineration unit consistent with system (CMS), where a CMS includes a unit such that the measurement is the provisions of the applicable CAA continuous parameter monitoring representative of control of the exhaust section 129 standards. system (CPMS) as well as a continuous emissions (e.g., on or downstream of the (g) If you no longer meet the emissions monitoring system (CEMS), last control device). See § 63.10010(a) definition of an EGU subject to this you must develop a site-specific for further details. For CPMS subpart you must be in compliance with monitoring plan and submit this site- installations, follow the procedures in any newly applicable standards on the specific monitoring plan, if requested, at § 63.10010(h). date you are no longer subject to this least 60 days before your initial (ii) Performance and equipment subpart. The date you are no longer performance evaluation (where specifications for the sample interface, subject to this subpart is a date selected applicable) of your CMS. This the pollutant concentration or by you, that must be at least 6 months requirement also applies to you if you parametric signal analyzer, and the data from the date that you last met the petition the Administrator for collection and reduction systems. definition of an EGU subject to this alternative monitoring parameters under (iii) Schedule for conducting initial subpart or the date you begin § 63.8(f). This requirement to develop and periodic performance evaluations. combusting solid waste, consistent with and submit a site-specific monitoring (iv) Performance evaluation § 63.9983(d). Your source must remain plan does not apply to affected sources procedures and acceptance criteria (e.g., in compliance with this subpart until with existing monitoring plans that calibrations), including ongoing data the date you select to cease complying apply to CEMS and CPMS prepared quality assurance procedures in with this subpart or the date you begin under Appendix B to part 60 or part 75 accordance with the general combusting solid waste, whichever is of this chapter, and that meet the requirements of § 63.8(d). earlier. requirements of § 63.10010. Using the (v) On-going operation and (h)(1) If you own or operate an EGU process described in § 63.8(f)(4), you maintenance procedures, in accordance that does not meet the definition of an may request approval of monitoring with the general requirements of EGU subject to this subpart on April 16, system quality assurance and quality §§ 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii). 2015, and you commence or control procedures alternative to those (vi) Conditions that define a CMS that recommence operations that cause you specified in this paragraph of this is out of control consistent with to meet the definition of an EGU subject section and, if approved, include those § 63.8(c)(7)(i) and for responding to out to this subpart, you are subject to the in your site-specific monitoring plan. of control periods consistent with provisions of this subpart, including, The monitoring plan must address the §§ 63.8(c)(7)(ii) and (c)(8). but not limited to, the emission provisions in paragraphs (d)(2) through (vii) On-going recordkeeping and limitations and the monitoring (5) of this section. reporting procedures, in accordance requirements, as of the first day you (2) The site-specific monitoring plan with the general requirements of meet the definition of an EGU subject to shall include the information specified §§ 63.10(c), (e)(1), and (e)(2)(i), or as this subpart. You must complete all in paragraphs (d)(5)(i) through (d)(5)(vii) specifically required under this subpart. initial compliance demonstrations for of this section. Alternatively, the (e) As part of your demonstration of this subpart applicable to your EGU requirements of paragraphs (d)(5)(i) continuous compliance, you must within 180 days after you commence or through (d)(5)(vii) are considered to be perform periodic tune-ups of your recommence operations that cause you met for a particular CMS or sorbent trap EGU(s), according to § 63.10021(e). to meet the definition of an EGU subject monitoring system if: (f) You are subject to the requirements to this subpart. (i) The CMS or sorbent trap of this subpart for at least 6 months (2) You must provide 30 days prior monitoring system is installed, certified, following the last date you met the notice of the date you intend to maintained, operated, and quality- definition of an EGU subject to this commence or recommence operations assured either according to part 75 of subpart (e.g., 6 months after a that cause you to meet the definition of this chapter, or appendix A or B to this cogeneration unit provided more than an EGU subject to this subpart. The subpart; and one third of its potential electrical notification must identify: (ii) The recordkeeping and reporting output capacity and more than 25 (i) The name of the owner or operator requirements of part 75 of this chapter, megawatts electrical output to any of the EGU, the location of the facility, or appendix A or B to this subpart, that power distributions system for sale). the unit(s) that will commence or pertain to the CMS are met. You may opt to remain subject to the recommence operations that will cause (3) If requested by the Administrator, provisions of this subpart beyond 6 the unit(s) to meet the definition of an you must submit the monitoring plan months after the last date you met the EGU subject to this subpart, and the (or relevant portion of the plan) at least definition of an EGU subject to this date of the notice; 60 days before the initial performance subpart, unless you are a solid waste (ii) The 40 CFR part 60, part 62, or evaluation of a particular CMS, except incineration unit subject to standards part 63 subpart and subcategory

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currently applicable to your unit(s), and subpart. All calibration and drift checks personal injury, or severe property the subcategory of this subpart that will must be performed as of the date your damage; and be applicable after you commence or source ceases to be or becomes subject (5) All possible steps were taken to recommence operation that will cause to this subpart. You must also comply minimize the impact of the excess the unit(s) to meet the definition of an with provisions of §§ 63.10010, emissions on ambient air quality, the EGU subject to this subpart; 63.10020, and 63.10021 of this subpart. environment and human health; and (iii) The date on which you became Relative accuracy tests must be (6) All emissions monitoring and subject to the currently applicable performed as of the performance test control systems were kept in operation emission limits; deadline for PM CEMS, if applicable. if at all possible, consistent with safety (iv) The date upon which you will Relative accuracy testing for other and good air pollution control practices; commence or recommence operations CEMS need not be repeated if that and that will cause your unit to meet the testing was previously performed (7) All of the actions in response to definition of an EGU subject to this consistent with CAA section 112 the excess emissions were documented subpart, consistent with paragraph (f) of monitoring requirements or monitoring by properly signed, contemporaneous this section. requirements under this subpart. operating logs; and (i)(1) If you own or operate an EGU (8) At all times, the affected source § 63.10001 Affirmative defense for subject to this subpart, and it has been was operated in a manner consistent at least 6 months since you operated in exceedence of emission limit during malfunction. with good practices for minimizing a manner that caused you to meet the emissions; and definition of an EGU subject to this In response to an action to enforce the standards set forth in § 63.9991 you may (9) A written root cause analysis has subpart, you may, consistent with been prepared, the purpose of which is paragraph (g) of this section, select the assert an affirmative defense to a claim for civil penalties for exceedances of to determine, correct, and eliminate the date on which your EGU will no longer primary causes of the malfunction and be subject to this subpart. You must be such standards that are caused by malfunction, as defined at 40 CFR 63.2. the excess emissions resulting from the in compliance with any newly malfunction event at issue. The analysis applicable section 112 or 129 standards Appropriate penalties may be assessed, however, if you fail to meet your burden shall also specify, using best monitoring on the date you selected. methods and engineering judgment, the (2) You must provide 30 days prior of proving all of the requirements in the amount of excess emissions that were notice of the date your EGU will cease affirmative defense. The affirmative the result of the malfunction. complying with this subpart. The defense shall not be available for claims (b) Notification. The owner or notification must identify: for injunctive relief. (i) The name of the owner or operator (a) To establish the affirmative operator of the affected source of the EGU(s), the location of the defense in any action to enforce such a experiencing an exceedance of its facility, the EGU(s) that will cease limit, you must timely meet the emission limit(s) during a malfunction complying with this subpart, and the notification requirements in paragraph shall notify the Administrator by date of the notice; (b) of this section, and must prove by a telephone or facsimile (FAX) (ii) The currently applicable preponderance of evidence that: transmission as soon as possible, but no subcategory under this subpart, and any (1) The excess emissions: later than two business days after the 40 CFR part 60, part 62, or part 63 (i) Were caused by a sudden, initial occurrence of the malfunction or, subpart and subcategory that will be infrequent, and unavoidable failure of if it is not possible to determine within applicable after you cease complying air pollution control and monitoring two business days whether the with this subpart; equipment, process equipment, or a malfunction caused or contributed to an (iii) The date on which you became process to operate in a normal or usual exceedance, no later than two business subject to this subpart; manner, and days after the owner or operator knew (iv) The date upon which you will (ii) Could not have been prevented or should have known that the cease complying with this subpart, through careful planning, proper design malfunction caused or contributed to an consistent with paragraph (g) of this or better operation and maintenance exceedance, but, in no event later than section. practices; and two business days after the end of the (j) All air pollution control equipment (iii) Did not stem from any activity or averaging period, if it wishes to avail necessary for compliance with any event that could have been foreseen and itself of an affirmative defense to civil newly applicable emissions limits avoided, or planned for; and penalties for that malfunction. The which apply as a result of the cessation (iv) Were not part of a recurring owner or operator seeking to assert an or commencement or recommencement pattern indicative of inadequate design, affirmative defense shall also submit a of operations that cause your EGU to operation, or maintenance; and written report to the Administrator meet the definition of an EGU subject to (2) Repairs were made as within 45 days of the initial occurrence this subpart must be installed and expeditiously as possible when the of the exceedance of the standard in operational as of the date your source applicable emission limitations were § 63.9991 to demonstrate, with all ceases to be or becomes subject to this being exceeded. Off-shift and overtime necessary supporting documentation, subpart. labor were used, to the extent that it has met the requirements set forth (k) All monitoring systems necessary practicable to make these repairs; and in paragraph (a) of this section. The for compliance with any newly (3) The frequency, amount and owner or operator may seek an applicable monitoring requirements duration of the excess emissions extension of this deadline for up to 30 which apply as a result of the cessation (including any bypass) were minimized additional days by submitting a written or commencement or recommencement to the maximum extent practicable request to the Administrator before the of operations that cause your EGU to during periods of such emissions; and expiration of the 45 day period. Until a meet the definition of an EGU subject to (4) If the excess emissions resulted request for an extension has been this subpart must be installed and from a bypass of control equipment or approved by the Administrator, the operational as of the date your source a process, then the bypass was owner or operator is subject to the ceases to be or becomes subject to this unavoidable to prevent loss of life, requirement to submit such report

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within 45 days of the initial occurrence HF, PM, or SO2 emissions limit in Table then, provided that the certification and of the exceedance. 1 or 2 to this subpart. QA provisions of that program meet the (ii) If you choose to comply with an applicable requirements of Testing and Initial Compliance electrical output-based emission limit, §§ 63.10010(b) through (h), an Requirements you must collect hourly electrical load additional performance evaluation of § 63.10005 What are my initial compliance data during the performance test period. the CMS is not required under this requirements and by what date must I (b) Performance testing requirements. subpart. conduct them? If you choose to use performance testing (1) For an affected coal-fired, solid oil- (a) General requirements. For each of to demonstrate initial compliance with derived fuel-fired, or liquid oil-fired your affected EGUs, you must the applicable emissions limits in EGU, you may demonstrate initial demonstrate initial compliance with Tables 1 and 2 to this subpart for your compliance with the applicable SO2, each applicable emissions limit in Table EGUs, you must conduct the tests HCl, or HF emissions limit in Table 1 1 or 2 of this subpart through according to § 63.10007 and Table 5 to or 2 of this subpart through use of an performance testing. Where two this subpart. For the purposes of the SO2, HCl, or HF CEMS installed and emissions limits are specified for a initial compliance demonstration, you operated in accordance with part 75 of particular pollutant (e.g., a heat input- may use test data and results from a this chapter or Appendix B to this based limit in lb/MMBtu and an performance test conducted prior to the subpart, as applicable. You may also electrical output-based limit in lb/ date on which compliance is required as demonstrate compliance with a MWh), you may demonstrate specified in § 63.9984, provided that the filterable PM emission limit in Table 1 compliance with either emission limit. following conditions are fully met: or 2 of this subpart through use of a PM (1) For a performance test based on For a particular compliance CEMS installed, certified, and operated stack test data, the test was conducted demonstration, you may be required to in accordance with § 63.10010(i). Initial no more than 12 calendar months prior conduct one or more of the following compliance is achieved if the arithmetic to the date on which compliance is activities in conjunction with average of 30-boiler operating days of required as specified in § 63.9984; performance testing: collection of quality-assured CEMS data, expressed (2) For a performance test based on hourly electrical load data (megawatts); in units of the standard (see data from a certified CEMS or sorbent § 63.10007(e)), meets the applicable establishment of operating limits trap monitoring system, the test consists SO , PM, HCl, or HF emissions limit in according to § 63.10011 and Tables 4 2 of all valid data CMS data recorded in Table 1 or 2 to this subpart. Use and 7 to this subpart; and CMS the 30 boiler operating days Equation 19–19 of Method 19 in performance evaluations. In all cases, immediately preceding that date; appendix A–7 to part 60 of this chapter you must demonstrate initial (3) The performance test was to calculate the 30-boiler operating day compliance no later than the applicable conducted in accordance with all average emissions rate. (Note: for this date in paragraph (f) of this section for applicable requirements in § 63.10007 calculation, the term E in Equation 19– tune-up work practices for existing hj and Table 5 to this subpart; 19 must be in the same units of measure EGUs, in § 63.9984 for other (4) A record of all parameters needed as the applicable HCl or HF emission requirements for existing EGUs, and in to convert pollutant concentrations to limit in Table 1 or 2 to this subpart). paragraph (g) of this section for all units of the emission standard (e.g., (2) For affected coal-fired or solid oil- requirements for new EGUs. stack flow rate, diluent gas derived fuel-fired EGUs that (1) To demonstrate initial compliance concentrations, hourly electrical loads) demonstrate compliance with the with an applicable emissions limit in is available for the entire performance applicable emission limits for total non- Table 1 or 2 to this subpart using stack test period; and mercury HAP metals, individual non- testing, the initial performance test (5) For each performance test based mercury HAP metals, total HAP metals, generally consists of three runs at on stack test data, you certify, and keep individual HAP metals, or filterable PM specified process operating conditions documentation demonstrating, that the listed in Table 1 or 2 to this subpart using approved methods. If you are EGU configuration, control devices, and using initial performance testing and required to establish operating limits fuel(s) have remained consistent with continuous monitoring with PM CPMS: (see paragraph (d) of this section and conditions since the prior performance (i) You must demonstrate initial Table 4 to this subpart), you must test was conducted. compliance no later than the applicable collect all applicable parametric data (c) Operating limits. In accordance date specified in § 63.9984(f) for existing during the performance test period. with § 63.10010 and Table 4 to this EGUs and in paragraph (g) of this Also, if you choose to comply with an subpart, you may be required to section for new EGUs. electrical output-based emission limit, establish operating limits using PM (ii) You must demonstrate continuous you must collect hourly electrical load CPMS and using site-specific compliance with the PM CPMS site- data during the test period. monitoring for certain liquid oil-fired specific operating limit that (2) To demonstrate initial compliance units as part of your initial compliance corresponding to the results of the using either a CMS that measures HAP demonstration. performance test demonstrating concentrations directly (i.e., an Hg, HCl, (d) CMS requirements. If, for a compliance with the pollutant with or HF CEMS, or a sorbent trap particular emission or operating limit, which you choose to comply. monitoring system) or an SO2 or PM you are required to (or elect to) (iii) You must repeat the performance CEMS, the initial performance test demonstrate initial compliance using a test annually for the selected pollutant consists of 30 boiler operating days of continuous monitoring system, the CMS emissions limit and reassess and adjust data collected by the initial compliance must pass a performance evaluation the site-specific operating limit in demonstration date specified in prior to the initial compliance accordance with the results of the § 63.10005 with the certified monitoring demonstration. If a CMS has been performance test. system. previously certified under another state (3) For affected EGUs that are either (i) The 30-boiler operating day CMS or federal program and is continuing to required to or elect to demonstrate performance test must demonstrate meet the on-going quality-assurance initial compliance with the applicable compliance with the applicable Hg, HCl, (QA) requirements of that program, Hg emission limit in Table 1 or 2 of this

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subpart using Hg CEMS or sorbent trap than 180 days after April 16, 2012 or specified in Table 1 or 2 nominally by monitoring systems, initial compliance within 180 days after startup of the a factor of two. must be demonstrated no later than the source, whichever is later, according to (ii) Follow the instructions in applicable date specified in § 63.9984(f) § 63.7(a)(2)(ix). § 63.10007(e) and Table 5 to this subpart for existing EGUs and in paragraph (g) (1) For the new or reconstructed to convert the test data to the units of of this section for new EGUs. Initial affected source described in this the applicable standard. compliance is achieved if the arithmetic paragraph (g), if you choose to comply (3) For Hg, you must conduct a 30- average of 30-boiler operating days of with the proposed emission limits when boiler operating day performance test quality-assured CEMS (or sorbent trap demonstrating initial compliance, you using Method 30B in appendix A–8 to monitoring system) data, expressed in must conduct a second compliance part 60 of this chapter to determine units of the standard (see section 6.2 of demonstration for the promulgated whether a unit qualifies for LEE status. appendix A to this subpart), meets the emission limits within 3 years after Locate the Method 30B sampling probe applicable Hg emission limit in Table 1 April 16, 2012 or within 3 years after tip at a point within the 10 percent or 2 to this subpart. startup of the affected source, whichever centroidal area of the duct at a location (4) For affected liquid oil-fired EGUs is later. that meets Method 1 in appendix A–1 that demonstrate compliance with the (2) If your new or reconstructed to part 60 of this chapter and conduct applicable emission limits for HCl or HF affected source commences construction at least three nominally equal length test listed in Table 1 or 2 to this subpart or reconstruction after April 16, 2012, runs over the 30-boiler operating day using quarterly testing and continuous you must demonstrate initial test period. Collect Hg emissions data monitoring with a CMS: compliance with the promulgated continuously over the entire test period (i) You must demonstrate initial emission limits no later than 180 days (except when changing sorbent traps or compliance no later than the applicable after startup of the source. performing required reference method date specified in § 63.9984 for existing (h) Low emitting EGUs. The QA procedures), under all process EGUs and in paragraph (g) of this provisions of this paragraph (h) apply to operating conditions. You may use a section for new EGUs. pollutants with emissions limits from pair of sorbent traps to sample the stack (ii) You must demonstrate continuous new EGUs except Hg and to all gas for no more than 10 days. compliance with the CMS site-specific pollutants with emissions limits from (i) Depending on whether you intend operating limit that corresponding to the existing EGUs. You may not pursue this to assess LEE status for Hg in terms of results of the performance test compliance option if your existing EGU the lb/TBtu or lb/GWh emission limit in demonstrating compliance with the HCl is equipped with an acid gas scrubber Table 2 to this subpart or in terms of the or HF emissions limit. and has a main stack and bypass stack annual Hg mass emissions limit of 29.0 (iii) You must repeat the performance exhaust configuration. lb/year, you will have to collect some or test annually for the HCl or HF (1) An EGU may qualify for low all of the following data during the 30- emissions limit and reassess and adjust emitting EGU (LEE) status for Hg, HCl, boiler operating day test period (see the site-specific operating limit in HF, filterable PM, total non-Hg HAP paragraph (h)(3)(iii) of this section): accordance with the results of the metals, or individual non-Hg HAP (A) Diluent gas (CO2 or O2) data, using performance test. metals (or total HAP metals or either Method 3A in appendix A–3 to (e) Tune-ups. All affected EGUs are individual HAP metals, for liquid oil- part 60 of this chapter or a diluent gas subject to the work practice standards in fired EGUs) if you collect performance monitor that has been certified Table 3 of this subpart. As part of your test data that meet the requirements of according to part 75 of this chapter. initial compliance demonstration, you this paragraph (h), and if those data (B) Stack gas flow rate data, using must conduct a performance tune-up of demonstrate: either Method 2, 2F, or 2G in your EGU according to § 63.10021(e). (i) For all pollutants except Hg, appendices A–1 and A–2 to part 60 of (f) For existing affected sources a performance test emissions results less this chapter, or a flow rate monitor that tune-up may occur prior to April 16, than 50 percent of the applicable has been certified according to part 75 2012, so that existing sources without emissions limits in Table 1 or 2 to this of this chapter. neural networks have up to 42 calendar subpart for all required testing for 3 (C) Stack gas moisture content data, months (3 years from promulgation plus consecutive years; or using either Method 4 in appendix A– 180 days) or, in the case of units (ii) For Hg emissions from an existing 1 to part 60 of this chapter, or a employing neural network combustion EGU, either: moisture monitoring system that has controls, up to 54 calendar months (48 (A) Average emissions less than 10 been certified according to part 75 of months from promulgation plus 180 percent of the applicable Hg emissions this chapter. Alternatively, an days) after the date that is specified for limit in Table 2 to this subpart appropriate fuel-specific default your source in § 63.9984 and according (expressed either in units of lb/TBtu or moisture value from § 75.11(b) of this to the applicable provisions in lb/GWh); or chapter may be used in the calculations § 63.7(a)(2) as cited in Table 9 to this (B) Potential Hg mass emissions of or you may petition the Administrator subpart to demonstrate compliance with 29.0 or fewer pounds per year and under § 75.66 of this chapter for use of this requirement. If a tune-up occurs compliance with the applicable Hg a default moisture value for non-coal- prior to such date, the source must emission limit in Table 2 to this subpart fired units. maintain adequate records to show that (expressed either in units of lb/TBtu or (D) Hourly electrical load data the tune-up met the requirements of this lb/GWh). (megawatts), from facility records. standard. (2) For all pollutants except Hg, you (ii) If you use CEMS to measure CO2 (g) If your new or reconstructed must conduct all required performance (or O2) concentration, and/or flow rate, affected source commenced tests described in § 63.10007 to and/or moisture, record hourly average construction or reconstruction between demonstrate that a unit qualifies for LEE values of each parameter throughout the May 3, 2011, and July 2, 2011, you must status. 30-boiler operating day test period. If demonstrate initial compliance with (i) When conducting emissions testing you opt to use EPA reference methods either the proposed emission limits or to demonstrate LEE status, you must rather than CEMS for any parameter, the promulgated emission limits no later increase the minimum sample volume you must perform at least one

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representative test run on each option, the units in the configuration (ii) ASTM D4006–11, ‘‘Standard Test operating day of the test period, using qualify for LEE status if: Method for Water in Crude Oil by the applicable reference method. (i) The emission rate measured at the Distillation,’’ including Annex A1 and (iii) Calculate the average Hg common stack is less than 50 percent Appendix A1, or concentration, in mg/m3 (dry basis), for (10 percent for Hg) of the applicable (iii) ASTM D4177–95 (Reapproved the 30-boiler operating day performance emission limit in Table 1 or 2 to this 2010), ‘‘Standard Practice for Automatic test, as the arithmetic average of all subpart; or Sampling of Petroleum and Petroleum Method 30B sorbent trap results. Also (ii) For Hg from an existing EGU, the Products,’’ including Annexes A1 calculate, as applicable, the average applicable Hg emission limit in Table 2 through A6 and Appendices X1 and X2, values of CO2 or O2 concentration, stack to this subpart is met and the potential or gas flow rate, stack gas moisture annual mass emissions, calculated (iv) ASTM D4057–06 (Reapproved content, and electrical load for the test according to paragraph (h)(3)(iii) of this 2011), ‘‘Standard Practice for Manual period. Then: section (with some modifications), are Sampling of Petroleum and Petroleum (A) To express the test results in units less than or equal to 29.0 pounds times Products,’’ including Annex A1. of lb/TBtu, follow the procedures in the number of units sharing the (5) Should the moisture in your liquid § 63.10007(e). Use the average Hg common stack. Base your calculations fuel be more than 1.0 percent by weight, concentration and diluent gas values in on the combined heat input capacity of you must the calculations. all units sharing the stack (i.e., either (i) Conduct HCl and HF emissions (B) To express the test results in units the combined maximum rated value or, testing quarterly (and monitor site- of lb/GWh, use Equations A–3 and A– if applicable, a lower combined value specific operating parameters as 4 in section 6.2.2 of appendix A to this restricted by permit conditions or provided in § 63.10000(c)(2)(iii) or subpart, replacing the hourly values operating hours). (ii) Use an HCl CEMS and/or HF ‘‘Ch’’, ‘‘Qh’’, ‘‘Bws’’ and ‘‘(MW)h’’ with the (5) For an affected unit with a CEMS. average values of these parameters from multiple stack or duct configuration in (j) Startup and shutdown for coal- the performance test. which the exhaust stacks or ducts are fired or solid oil derived-fired units. (C) To calculate pounds of Hg per downstream of all emission control You must follow the requirements given year, use one of the following methods: devices, you must perform a separate in Table 3 to this subpart. (1) Multiply the average lb/TBtu Hg emission test in each stack or duct. The (k) You must submit a Notification of emission rate (determined according to unit qualifies for LEE status if: Compliance Status summarizing the paragraph (h)(3)(iii)(A) of this section) (i) The emission rate, based on all test results of your initial compliance by the maximum potential annual heat runs performed at all of the stacks or demonstration, as provided in input to the unit (TBtu), which is equal ducts, is less than 50 percent (10 § 63.10030. to the maximum rated unit heat input percent for Hg) of the applicable (TBtu/hr) times 8,760 hours. If the emission limit in Table 1 or 2 to this § 63.10006 When must I conduct subsequent performance tests or tune-ups? maximum rated heat input value is subpart; or expressed in units of MMBtu/hr, (ii) For Hg from an existing EGU, the (a) For liquid oil-fired, solid oil- multiply it by 106 to convert it to TBtu/ applicable Hg emission limit in Table 2 derived fuel- and coal-fired EGUs and hr; or to this subpart is met and the potential IGCC units using PM CPMS to monitor (2) Multiply the average lb/GWh Hg annual mass emissions, calculated continuous performance with an emission rate (determined according to according to paragraph (h)(3)(iii) of this applicable emission limit as provided paragraph (h)(3)(iii)(B) of this section) section, are less than or equal to 29.0 for under § 63.10000(c), you must by the maximum potential annual pounds. Use the average Hg emission conduct all applicable performance tests electricity generation (GWh), which is rate from paragraph (h)(5)(i) of this according to Table 5 to this subpart and equal to the maximum rated electrical section in your calculations. § 63.10007 at least every year. output of the unit (GW) times 8,760 (i) Liquid-oil fuel moisture (b) For affected units meeting the LEE hours. If the maximum rated electrical measurement. If your EGU combusts requirements of § 63.10005(h), you must output value is expressed in units of liquid fuels, if your fuel moisture repeat the performance test once every MW, multiply it by 103 to convert it to content is no greater than 1.0 percent by 3 years (once every year for Hg) GW; or weight, and if you would like to according to Table 5 and § 63.10007. (3) If an EGU has a federally- demonstrate initial and ongoing Should subsequent emissions testing enforceable permit limit on either the compliance with HCl and HF emissions results show the unit does not meet the annual heat input or the number of limits, you must meet the requirements LEE eligibility requirements, LEE status annual operating hours, you may of paragraphs (i)(1) through (5) of this is lost. If this should occur: modify the calculations in paragraph section. (1) For all pollutant emission limits (h)(3)(iii)(C)(1) of this section by (1) Measure fuel moisture content of except for Hg, you must conduct replacing the maximum potential each shipment of fuel if your fuel emissions testing quarterly, except as annual heat input or 8,760 unit arrives on a batch basis; or otherwise provided in § 63.10021(d)(1). operating hours with the permit limit on (2) Measure fuel moisture content (2) For Hg, you must install, certify, annual heat input or operating hours (as daily if your fuel arrives on a maintain, and operate a Hg CEMS or a applicable). continuous basis; or sorbent trap monitoring system in (4) For a group of affected units that (3) Obtain and maintain a fuel accordance with appendix A to this vent to a common stack, you may either moisture certification from your fuel subpart, within 6 calendar months of assess LEE status for the units supplier. losing LEE eligibility. Until the Hg individually by performing a separate (4) Use one of the following methods CEMS or sorbent trap monitoring system emission test of each unit in the duct to determine fuel moisture content: is installed, certified, and operating, you leading from the unit to the common (i) ASTM D95–05 (Reapproved 2010), must conduct Hg emissions testing stack, or you may perform a single ‘‘Standard Test Method for Water in quarterly, except as otherwise provided emission test in the common stack. If Petroleum Products and Bituminous in § 63.10021(d)(1). You must have 3 you choose the common stack testing Materials by Distillation,’’ or calendar years of testing and CEMS or

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sorbent trap monitoring system data that over a consecutive 3-year period show site specific normal operations during satisfy the LEE emissions criteria to compliance with the LEE criteria. each test run. reestablish LEE status. (i) If you are required to meet an (b) You must conduct each (c) Except where paragraphs (a) or (b) applicable tune-up work practice performance test (including traditional of this section apply, or where you standard, you must conduct a 3-run stack tests, 30-boiler operating day install, certify, and operate a PM CEMS performance tune-up according to tests based on CEMS data (or sorbent to demonstrate compliance with a § 63.10021(e). trap monitoring system data), and 30- filterable PM emission limit, for liquid (1) For EGUs not employing neural boiler operating day Hg emission tests oil-fired EGUs, you must conduct all network combustion optimization for LEE qualification) according to the applicable periodic emissions tests for during normal operation, each requirements in Table 5 to this subpart. filterable PM, or individual or total HAP performance tune-up specified in (c) If you choose to comply with the metals emissions according to Table 5 to § 63.10021(e) must be no more than 36 filterable PM emission limit and this subpart and § 63.10007 at least calendar months after the previous demonstrate continuous performance quarterly, except as otherwise provided performance tune-up. using a PM CPMS for an applicable in § 63.10021(d)(1). (2) For EGUs employing neural emission limit as provided for in (d) Except where paragraph (b) of this network combustion optimization § 63.10000(c), you must also establish section applies, for solid oil-derived systems during normal operation, each an operating limit according to fuel- and coal-fired EGUs that do not performance tune-up specified in § 63.10011(b)(5) and Tables 4 and 6 to use either an HCl CEMS to monitor § 63.10021(e) must be no more than 48 this subpart. Should you desire to have operating limits that correspond to loads compliance with the HCl limit or an SO2 calendar months after the previous CEMS to monitor compliance with the performance tune-up. other than maximum normal operating load, you must conduct testing at those alternate equivalent SO2 emission limit, (j) You must report the results of you must conduct all applicable performance tests and performance other loads to determine the additional operating limits. periodic HCl emissions tests according tune-ups within 60 days after the (d) Except for a 30-boiler operating to Table 5 to this subpart and § 63.10007 completion of the performance tests and day performance test based on CEMS (or at least quarterly, except as otherwise performance tune-ups. The reports for all subsequent performance tests must sorbent trap monitoring system) data, provided in § 63.10021(d)(1). where the concept of test runs does not (e) Except where paragraph (b) of this include all applicable information required in § 63.10031. apply, you must conduct a minimum of section applies, for liquid oil-fired EGUs three separate test runs for each without HCl CEMS, HF CEMS, or HCl § 63.10007 What methods and other performance test, as specified in and HF CEMS, you must conduct all procedures must I use for the performance § 63.7(e)(3). Each test run must comply applicable emissions tests for HCl, HF, tests? with the minimum applicable sampling or HCl and HF emissions according to (a) Except as otherwise provided in time or volume specified in Table 1 or Table 5 to this subpart and § 63.10007 this section, you must conduct all 2 to this subpart. Sections 63.10005(d) at least quarterly, except as otherwise required performance tests according to and (h), respectively, provide special provided in § 63.10021(d)(1), and § 63.7(d), (e), (f), and (h). You must also instructions for conducting performance conduct site-specific monitoring under a develop a site-specific test plan tests based on CEMS or sorbent trap plan as provided for in according to the requirements in monitoring systems, and for conducting § 63.10000(c)(2)(iii). § 63.7(c). emission tests for LEE qualification. (f) Unless you follow the requirements (1) If you use CEMS (Hg, HCl, SO2, or (e) To use the results of performance listed in paragraphs (g) and (h) of this other) to determine compliance with a testing to determine compliance with section, performance tests required at 30-boiler operating day rolling average the applicable emission limits in Table least every 3 calendar years must be emission limit, you must collect data for 1 or 2 to this subpart, proceed as completed within 35 to 37 calendar all nonexempt unit operating conditions follows: months after the previous performance (see § 63.10011(g) and Table 3 to this (1) Except for a 30-boiler operating test; performance tests required at least subpart). day performance test based on CEMS (or every year must be completed within 11 (2) If you conduct performance testing sorbent trap monitoring system) data, if to 13 calendar months after the previous with test methods in lieu of continuous measurement results for any pollutant performance test; and performance tests monitoring, operate the unit at are reported as below the method required at least quarterly must be maximum normal operating load detection level (e.g., laboratory completed within 80 to 100 calendar conditions during each periodic (e.g., analytical results for one or more days after the previous performance test, quarterly) performance test. Maximum sample components are below the except as otherwise provided in normal operating load will be generally method defined analytical detection § 63.10021(d)(1). between 90 and 110 percent of design level), you must use the method (g) If you elect to demonstrate capacity but should be representative of detection level as the measured compliance using emissions averaging site specific normal operations during emissions level for that pollutant in under § 63.10009, you must continue to each test run. calculating compliance. The measured conduct performance stack tests at the (3) For establishing operating limits result for a multiple component analysis appropriate frequency given in section with particulate matter continuous (e.g., analytical values for multiple (c) through (f) of this section. parametric monitoring system (PM Method 29 fractions both for individual (h) If a performance test on a non- CPMS) to demonstrate compliance with HAP metals and for total HAP metals) mercury LEE shows emissions in excess a PM or non Hg metals emissions limit, may include a combination of method of 50 percent of the emission limit and operate the unit at maximum normal detection level data and analytical data if you choose to reapply for LEE status, operating load conditions during the reported above the method detection you must conduct performance tests at performance test period. Maximum level. the appropriate frequency given in normal operating load will be generally (2) If the limits are expressed in lb/ section (c) through (e) of this section for between 90 and 110 percent of design MMBtu or lb/TBtu, you must use the F- that pollutant until all performance tests capacity but should be representative of factor methodology and equations in

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sections 12.2 and 12.3 of EPA Method appendix A to this subpart to calculate subcategories of such EGUs are equal to 19 in appendix A–7 to part 60 of this the pollutant emission rate in lb/GWh. or less than the applicable emissions chapter. In cases where an appropriate In this calculation, define (M)h as the limit in Table 2, according to the F-factor is not listed in Table 19–2 of calculated pollutant mass emission rate procedures in this section. Note that Method 19, you may use F-factors from for the performance test (lb/h), and except for Hg emissions from EGUs in Table 1 in section 3.3.5 of appendix F define (MW)h as the average electrical the ‘‘unit designed for coal ≥ 8,300 Btu/ to part 75 of this chapter, or F-factors load during the performance test lb’’ subcategory, the averaging time for derived using the procedures in section (megawatts). If the applicable emission emissions averaging for pollutants is 30 3.3.6 of appendix to part 75 of this limit is in lb/MWh rather than lb/GWh, days (rolling daily) using data from chapter. Use the following factors to omit the 103 term from Equation A–4 to CEMS or a combination of data from convert the pollutant concentrations determine the pollutant emission rate in CEMS and manual performance testing. measured during the initial performance lb/MWh. The averaging time for emissions tests to units of lb/scf, for use in the (f) Upon request, you shall make averaging for Hg from EGUs in the ‘‘unit applicable Method 19 equations: available to the EPA Administrator such designed for coal ≥ 8,300 Btu/lb’’ × ¥7 (i) Multiply SO2 ppm by 1.66 10 ; records as may be necessary to subcategory is 90 days (rolling daily) × ¥8 (ii) Multiply HCl ppm by 9.43 10 ; determine whether the performance using data from CEMS, sorbent trap × ¥8 (iii) Multiply HF ppm by 5.18 10 ; tests have been done according to the monitoring, or a combination of (iv) Multiply HAP metals requirements of this section. monitoring data and data from manual concentrations (mg/dscm) by 6.24 × performance testing. For the purposes of 10¥8; and § 63.10008 [Reserved] this paragraph, 30- (or 90-day) group (v) Multiply Hg concentrations (mg/ scm) by 6.24 × 10¥11. § 63.10009 May I use emissions averaging boiler operating days is defined as a (3) To determine compliance with to comply with this subpart? period during which at least one unit in emission limits expressed in lb/MWh or (a) General eligibility. (1) You may use the emissions averaging group has lb/GWh, you must first calculate the emissions averaging as described in operated 30 (or 90) days. You must pollutant mass emission rate during the paragraph (a)(2) of this section as an calculate the weighted average performance test, in units of lb/h. For alternative to meeting the requirements emissions rate for the group in Hg, if a CEMS or sorbent trap of § 63.9991 for filterable PM, SO2, HF, accordance with the procedures in this monitoring system is used, use Equation HCl, non-Hg HAP metals, or Hg on an paragraph using the data from all units A–2 or A–3 in appendix A to this EGU-specific basis if: in the group including any that operate subpart (as applicable). In all other (i) You have more than one existing fewer than 30 (or 90) days during the cases, use an equation that has the EGU in the same subcategory located at preceding 30 (or 90) group boiler days. general form of Equation A–2 or A–3, one or more contiguous properties, (i) You may choose to have your EGU replacing the value of K with 1.66 × belonging to a single major industrial emissions averaging group meet either ¥7 ¥8 10 lb/scf-ppm for SO2, 9.43 × 10 lb/ grouping, which are under common the heat input basis (MMBtu or TBtu, as scf-ppm for HCl (if an HCl CEMS is control of the same person (or persons appropriate for the pollutant) or gross used), 5.18 × 10¥8 lb/scf-ppm for HF (if under common control); and electrical output basis (MWh or GWh, as an HF CEMS is used), or 6.24 × 10¥8 lb- (ii) You use CEMS (or sorbent trap appropriate for the pollutant). scm/mg-scf for HAP metals and for HCl monitoring systems for determining Hg (ii) You may not mix bases within and HF (when performance stack testing emissions) or quarterly emissions your EGU emissions averaging group. is used), and defining Ch as the average testing for demonstrating compliance. (iii) You may use emissions averaging SO2, HCl, or HF concentration in ppm, (2) You may demonstrate compliance for affected units in different or the average HAP metals by emissions averaging among the subcategories if the units vent to the concentration in mg/dscm. This existing EGUs in the same subcategory, atmosphere through a common stack calculation requires stack gas if your averaged Hg emissions for EGUs (see paragraph (m) of this section). volumetric flow rate (scfh) and (in some in the ‘‘unit designed for coal ≥ 8,300 (b) Equations. Use the following cases) moisture content data (see Btu/lb’’ subcategory are equal to or less equations when performing calculations §§ 63.10005(h)(3) and 63.10010). Then, than 1.0 lb/TBtu or 1.1E–2 lb/GWh or if for your EGU emissions averaging if the applicable emission limit is in your averaged emissions of individual, group: units of lb/GWh, use Equation A–4 in other pollutants from other (1) Group eligibility equations.

Where: Rmmi = Maximum rated heat input or gross Teri = Emissions rate from most recent test WAERm = Weighted average emissions rate electrical output of unit i in terms of heat of unit i in terms of lb/heat input or lb/ maximum in terms of lb/heat input or lb/ input or gross electrical output, gross electrical output, gross electrical output, p = number of EGUs in emissions averaging Rmti = Maximum rated heat input or gross electrical output of unit i in terms of lb/ Hermi = Hourly emissions rate (e.g., lb/ group that rely on CEMS, heat input or lb/gross electrical output, MMBtu, lb/MWh) from CEMS or sorbent n = number of hourly rates collected over 30- and trap monitoring for hour i, group boiler operating days, m = number of EGUs in emissions averaging group that rely on emissions testing.

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Where: generated or gross electrical output per generated or gross electrical output per pound of steam generated, from unit i variables with similar names share the pound of steam generated, from unit i that uses CEMS or sorbent trap that uses emissions testing. descriptions for Equation 1a, monitoring, Smmi = maximum steam generation in units Smti = maximum steam generation in units (2) Weighted 30-day rolling average of pounds from unit i that uses CEMS or of pounds from unit i that uses emissions emissions rate equations for pollutants sorbent trap monitoring, testing, and other than Hg. Use equation 2a or 2b to Cfmi = conversion factor, calculated from the Cfti = conversion factor, calculated from the most recent emissions test results, in most recent emissions test results, in calculate the 30-day rolling average units of heat input per pound of steam units of heat input per pound of steam emissions daily.

Where: p = number of EGUs in emissions averaging Rti = Maximum rated heat input or gross group that rely on CEMS or sorbent trap electrical output of unit i in terms of lb/ Heri = hourly emission rate (e.g., lb/MMBtu, lb/MWh) from unit i’s CEMS for the monitoring, heat input or lb/gross electrical output, preceding 30-group boiler operating n = number of hourly rates collected over 30- and days, group boiler operating days, m = number of EGUs in emissions averaging Rmi = hourly heat input or gross electrical Teri = Emissions rate from most recent group that rely on emissions testing. output from unit i for the preceding 30- emissions test of unit i in terms of lb/ group boiler operating days, heat input or lb/gross electrical output,

Where: generated or gross electrical output per pound of steam generated, from unit i pound of steam generated, from unit i variables with similar names share the that uses emissions testing. that uses CEMS from the preceding 30- descriptions for Equation 2a, group boiler operating days, (3) Weighted 90-boiler operating day Smi = steam generation in units of pounds Sti = steam generation in units of pounds rolling average emissions rate equations from unit i that uses CEMS for the from unit i that uses emissions testing, for Hg emissions from EGUs in the ‘‘unit preceding 30-group boiler operating and designed for coal ≥ 8,300 Btu/lb’’ days, Cfti = conversion factor, calculated from the Cfmi = conversion factor, calculated from the most recent compliance test results, in subcategory. Use equation 3a or 3b to most recent compliance test results, in units of heat input per pound of steam calculate the 90-day rolling average units of heat input per pound of steam generated or gross electrical output per emissions daily.

Where: p = number of EGUs in emissions averaging Rti = Maximum rated heat input or gross group that rely on CEMS, electrical output of unit i in terms of lb/ Heri = hourly emission rate from unit i’s CEMS or Hg sorbent trap monitoring for n = number of hourly rates collected over the heat input or lb/gross electrical output, the preceding 90-group boiler operating 90-group boiler operating days, and days, Teri = Emissions rate from most recent m = number of EGUs in emissions averaging Rmi = hourly heat input or gross electrical emissions test of unit i in terms of lb/ group that rely on emissions testing. output from unit i for the preceding 90- heat input or lb/gross electrical output, group boiler operating days,

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Where: (f) Emissions averaging group (2) If you are not capable of variables with similar names share the eligibility demonstration. You must monitoring heat input or gross electrical descriptions for Equation 2a, demonstrate the ability for the EGUs output, you may use Equation 2b or 3b Smi = steam generation in units of pounds included in the emissions averaging of paragraph (b) of this section as an from unit i that uses CEMS or a Hg group to demonstrate initial compliance alternative to using Equation 2a of sorbent trap monitoring for the preceding according to paragraph (f)(1) or (2) of paragraph (b) of this section to calculate 90-group boiler operating days, this section using the maximum normal the average weighted emission rate Cfmi = conversion factor, calculated from the most recent compliance test results, in operating load of each EGU and the using the actual steam generation from units of heat input per pound of steam results of the initial performance tests. the units participating in the emissions generated or gross electrical output per For this demonstration and prior to averaging option. pound of steam generated, from unit i submitting your emissions averaging (h) CEMS (or sorbent trap monitoring) that uses CEMS or sorbent trap plan, if requested, you must conduct use. If an EGU in your emissions monitoring from the preceding 90-group required emissions monitoring for 30 averaging group uses CEMS (or a boiler operating days, days of boiler operation and any sorbent trap monitor for Hg emissions) St = steam generation in units of pounds i required manual performance testing to to demonstrate compliance, you must from unit i that uses emissions testing, use those data to determine the 30 (or and calculate an initial weighted average 90) group boiler operating day rolling Cfti = conversion factor, calculated from the emissions rate in accordance with this most recent emissions test results, in section. Should the Administrator average emissions rate. units of heat input per pound of steam require approval, you must submit your (i) Emissions testing. If you use generated or gross electrical output per proposed emissions averaging plan and manual emissions testing to pound of steam generated, from unit i supporting data at least 120 days before demonstrate compliance for one or more that uses emissions testing. April 16, 2015. If the Administrator EGUs in your emissions averaging (c) Separate stack requirements. For a requires approval of your plan, you may group, you must use the results from the group of two or more existing EGUs in not begin using emissions averaging most recent performance test to the same subcategory that each vent to until the Administrator approves your determine the 30 (or 90) day rolling a separate stack, you may average plan. average. You may use CEMS or sorbent trap data in combination with data from filterable PM, SO2, HF, HCl, non-Hg (1) You must use Equation 1a in HAP metals, or Hg emissions to paragraph (b) of this section to the most recent manual performance demonstrate compliance with the limits demonstrate that the maximum test in calculating the 30 (or 90) group in Table 2 to this subpart if you satisfy weighted average emissions rates of boiler operating day rolling average emissions rate. the requirements in paragraphs (d) filterable PM, HF, SO , HCl, non-Hg 2 (j) Emissions averaging plan. You through (j) of this section. HAP metals, or Hg emissions from the must develop an implementation plan (d) For each existing EGU in the existing units participating in the for emissions averaging according to the averaging group: emissions averaging option do not following procedures and requirements (1) The emissions rate achieved exceed the emissions limits in Table 2 during the initial performance test for in paragraphs (j)(1) and (2) of this to this subpart. the HAP being averaged must not section. (2) If you are not capable of exceed the emissions level that was (1) You must include the information monitoring heat input or gross electrical being achieved 180 days after April 16, contained in paragraphs (j)(1)(i) through output, and the EGU generates steam for 2015, or the date on which emissions (v) of this section in your testing done to support your emissions purposes other than generating implementation plan for all the averaging plan is complete (if the electricity, you may use Equation 1b of emissions units included in an Administrator does not require this section as an alternative to using emissions averaging: submission and approval of your Equation 1a of this section to (i) The identification of all existing emissions averaging plan), or the date demonstrate that the maximum EGUs in the emissions averaging group, that you begin emissions averaging, weighted average emissions rates of including for each either the applicable whichever is earlier; or filterable PM, HF, SO2, HCl, non-Hg HAP emission level or the control (2) The control technology employed HAP metals, or Hg emissions from the technology installed as of 180 days after during the initial performance test must existing units participating in the February 16, 2015, or the date on which not be less than the design efficiency of emissions averaging group do not you complete the emissions the emissions control technology exceed the emission limits in Table 2 to measurements used to support your employed 180 days after April 16, 2015 this subpart. emissions averaging plan (if the or the date that you begin emissions (g) You must determine the weighted Administrator does not require averaging, whichever is earlier. average emissions rate in units of the submission and approval of your (e) The weighted-average emissions applicable emissions limit on a 30 day emissions averaging plan), or the date rate from the existing EGUs rolling average (90 day rolling average that you begin emissions averaging, participating in the emissions averaging for Hg) basis according to paragraphs whichever is earlier; and the date on option must be in compliance with the (f)(1) through (3) of this section. The which you are requesting emissions limits in Table 2 to this subpart at all first averaging period begins on 30 (or averaging to commence; times following the compliance date 90 for Hg) days after February 16, 2015 (ii) The process weighting parameter specified 180 days after April 16, 2015, or the date that you begin emissions (heat input, gross electrical output, or or the date on which you complete the averaging, whichever is earlier. steam generated) that will be monitored emissions measurements used to (1) You must use Equation 2a or 3a of for each averaging group; support your emissions averaging plan paragraph (b) of this section to calculate (iii) The specific control technology or (if the Administrator does not require the weighted average emissions rate pollution prevention measure to be used submission and approval of your using the actual heat input or gross for each emission EGU in the averaging emissions averaging plan), or the date electrical output for each existing unit group and the date of its installation or that you begin emissions averaging, participating in the emissions averaging application. If the pollution prevention whichever is earlier. option. measure reduces or eliminates

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emissions from multiple EGUs, you affected units included in the emissions (ii) Install the required CEMS, PM must identify each EGU; averaging and from other units not CPMS, and sorbent trap monitoring (iv) The means of measurement (e.g., included in the emissions averaging systems in the common stack. CEMS, sorbent trap monitoring, manual (e.g., in a different subcategory) or other (3) Unit(s) utilizing common stack performance test) of filterable PM, SO2, nonaffected units all vent to the with non-affected unit(s). HF, HCl, individual or total non-Hg common stack, you must shut down the (i) When one or more affected units HAP metals, or Hg emissions in units not included in the emissions shares a common stack with one or accordance with the requirements in averaging and the nonaffected units or more non-affected units, you shall § 63.10007 and to be used in the vent their emissions to a different stack either: emissions averaging calculations; and during the performance test. (A) Install the required CEMS, PM (v) A demonstration that emissions Alternatively, you may conduct a CPMS, and sorbent trap monitoring averaging can produce compliance with performance test of the combined systems in the ducts leading to the each of the applicable emission limit(s) emissions in the common stack with all common stack from each affected unit; in accordance with paragraph (b)(1) of units operating and show that the or this section. combined emissions meet the most (B) Install the required CEMS, PM (2) If the Administrator requests you stringent emissions limit. You may also CPMS, and sorbent trap monitoring to submit the plan for review and use a CEMS or sorbent trap monitoring systems described in this section in the approval, you must submit a complete to apply this latter alternative to common stack and attribute all of the implementation plan at least 120 days demonstrate that the combined emissions measured at the common before April 16, 2015. If the emissions comply with the most stack to the affected unit(s). Administrator requests you to submit stringent emissions limit on a (ii) If you choose the common stack the plan for review and approval, you continuous basis. monitoring option: must receive approval before initiating (n) Combination requirements. The (A) For each hour in which valid data emissions averaging. common stack of a group of two or more are obtained for all parameters, you (i) The Administrator shall use existing EGUs in the same subcategory must calculate the pollutant emission following criteria in reviewing and subject to paragraph (k) of this section rate and approving or disapproving the plan: may be treated as a single stack for (B) You must assign the calculated (A) Whether the content of the plan purposes of paragraph (c) of this section pollutant emission rate to each unit that includes all of the information specified and included in an emissions averaging shares the common stack. in paragraph (h)(1) of this section; and group subject to paragraph (c) of this (4) Unit with a main stack and a (B) Whether the plan presents section. bypass stack. If the exhaust information sufficient to determine that configuration of an affected unit compliance will be achieved and § 63.10010 What are my monitoring, consists of a main stack and a bypass maintained. installation, operation, and maintenance stack, you shall install CEMS on both (ii) The Administrator shall not requirements? the main stack and the bypass stack, or, approve an emissions averaging (a) Flue gases from the affected units if it is not feasible to certify and quality- implementation plan containing any of under this subpart exhaust to the assure the data from a monitoring the following provisions: atmosphere through a variety of system on the bypass stack, you shall (A) Any averaging between emissions different configurations, including but install a CEMS only on the main stack of different pollutants or between units not limited to individual stacks, a and count bypass hours of deviation located at different facilities; or common stack configuration or a main from the monitoring requirements. (B) The inclusion of any emissions stack plus a bypass stack. For the CEMS, (5) Unit with a common control unit other than an existing unit in the PM CPMS, and sorbent trap monitoring device with multiple stack or duct same subcategory. systems used to provide data under this configuration. If the flue gases from an (k) Common stack requirements. For a subpart, the continuous monitoring affected unit, which is configured such group of two or more existing affected system installation requirements for that emissions are controlled with a units, each of which vents through a these exhaust configurations are as common control device or series of single common stack, you may average follows: control devices, are discharged to the emissions to demonstrate compliance (1) Single unit-single stack atmosphere through more than one with the limits in Table 2 to this subpart configurations. For an affected unit that stack or are fed into a single stack if you satisfy the requirements in exhausts to the atmosphere through a through two or more ducts, you may: paragraph (l) or (m) of this section. single, dedicated stack, you shall either (i) Install required CEMS, PM CPMS, (l) For a group of two or more existing install the required CEMS, PM CPMS, and sorbent trap monitoring systems in units in the same subcategory and and sorbent trap monitoring systems in each of the multiple stacks; which vent through a common the stack or at a location in the (ii) Install required CEMS, PM CPMS, emissions control system to a common ductwork downstream of all emissions and sorbent trap monitoring systems in stack that does not receive emissions control devices, where the pollutant and each of the ducts that feed into the from units in other subcategories or diluents concentrations are stack; categories, you may treat such averaging representative of the emissions that exit (iii) Install required CEMS, PM CPMS, group as a single existing unit for to the atmosphere. and sorbent trap monitoring systems in purposes of this subpart and comply (2) Unit utilizing common stack with one of the multiple stacks or ducts and with the requirements of this subpart as other affected unit(s). When an affected monitor the flows and dilution rates in if the group were a single unit. unit utilizes a common stack with one all multiple stacks or ducts in order to (m) For all other groups of units or more other affected units, but no non- determine total exhaust gas flow rate subject to paragraph (k) of this section, affected units, you shall either: and pollutant mass emissions rate in you may elect to conduct manual (i) Install the required CEMS, PM accordance with the applicable limit; or performance tests according to CPMS, and sorbent trap monitoring (iv) In the case of multiple ducts procedures specified in § 63.10007 in systems in the duct leading to the feeding into a single stack, install the common stack. If emissions from common stack from each unit; or CEMS, PM CPMS, and sorbent trap

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monitoring systems in the single stack emission standard in Table 1 of 2 to this calculate and record a 30-boiler as described in paragraph (a)(1) of this subpart, you must install, certify, operating day rolling average Hg section. operate, and maintain a moisture emission rate, in units of the standard, (6) Unit with multiple parallel control monitoring system in accordance with updated after each new boiler operating devices with multiple stacks. If the flue part 75 of this chapter. Alternatively, for day. Each 30-boiler operating day gases from an affected unit, which is coal-fired units, you may use rolling average emission rate, calculated configured such that emissions are appropriate fuel-specific default according to section 6.2 of appendix A controlled with multiple parallel control moisture values from § 75.11(b) of this to the subpart, is the average of all of the devices or multiple series of control chapter to estimate the moisture content valid hourly Hg emission rates in the devices are discharged to the of the stack gas or you may petition the preceding 30 boiler operating days. atmosphere through more than one Administrator under § 75.66 of this Section 7.1.4.3 of appendix A to this stack, you shall install the required chapter for use of a default moisture subpart explains how to reduce sorbent CEMS, PM CPMS, and sorbent trap value for non-coal-fired units. If you trap monitoring system data to an monitoring systems described in each of install and operate a moisture hourly basis. the multiple stacks. You shall calculate monitoring system, do not use substitute (h) If you use a PM CPMS to hourly flow-weighted average pollutant moisture data in the emissions demonstrate continuous compliance emission rates for the unit as follows: calculations. with an operating limit, you must (i) Calculate the pollutant emission (e) If you use an HCl and/or HF install, calibrate, maintain, and operate rate at each stack or duct for each hour CEMS, you must install, certify, operate, the PM CPMS and record the output of in which valid data are obtained for all maintain, and quality-assure the data the system as specified in paragraphs parameters; from the monitoring system in (h)(1) through (5) of this section. (ii) Multiply each calculated hourly accordance with appendix B to this (1) Install, calibrate, operate, and pollutant emission rate at each stack or subpart. Calculate and record a 30-boiler maintain your PM CPMS according to duct by the corresponding hourly stack operating day rolling average HCl or HF the procedures in your approved site- gas flow rate at that stack or duct; emission rate in the units of the specific monitoring plan developed in (iii) Sum the products determined standard, updated after each new boiler accordance with § 63.10000(d), and under paragraph (a)(5)(iii)(B) of this operating day. Each 30-boiler operating meet the requirements in paragraphs section; and day rolling average emission rate is the (h)(1)(i) through (iii) of this section. (iv) Divide the result obtained in average of all the valid hourly HCl or HF paragraph (a)(5)(iii)(C) of this section by (i) The operating principle of the PM emission rates in the preceding 30 boiler CPMS must be based on in-stack or the total hourly stack gas flow rate for operating days (see section 9.4 of extractive light scatter, light the unit, summed across all of the stacks appendix B to this subpart). scintillation, beta attenuation, or mass or ducts. (f)(1) If you use an SO CEMS, you 2 accumulation detection of the exhaust (b) If you use an oxygen (O2) or carbon must install the monitor at the outlet of gas or representative sample. The dioxide (CO2) CEMS to convert the EGU, downstream of all emission measured pollutant concentrations to control devices, and you must certify, reportable measurement output from the the units of the applicable emissions operate, and maintain the CEMS PM CPMS may be expressed as milliamps, stack concentration, or other limit, the O2 or CO2 concentrations shall according to part 75 of this chapter. raw data signal. be monitored at a location that (2) For on-going QA, the SO2 CEMS represents emissions to the atmosphere, must meet the applicable daily, (ii) The PM CPMS must have a cycle i.e., at the outlet of the EGU, quarterly, and semiannual or annual time (i.e., period required to complete downstream of all emission control requirements in sections 2.1 through 2.3 sampling, measurement, and reporting devices. You must install, certify, of appendix B to part 75 of this chapter, for each measurement) no longer than maintain, and operate the CEMS with the following addition: You must 60 minutes. according to part 75 of this chapter. Use perform the linearity checks required in (iii) The PM CPMS must be capable, only quality-assured O2 or CO2 data in section 2.2 of appendix B to part 75 of at a minimum, of detecting and responding to particulate matter the emissions calculations; do not use this chapter if the SO2 CEMS has a span part 75 substitute data values. value of 30 ppm or less. concentrations of 0.5 mg/acm. (c) If you are required to use a stack (3) Calculate and record a 30-boiler (2) For a new unit, complete the gas flow rate monitor, either for routine operating day rolling average SO2 initial PM CPMS performance operation of a sorbent trap monitoring emission rate in the units of the evaluation no later than October 13, system or to convert pollutant standard, updated after each new boiler 2012 or 180 days after the date of initial concentrations to units of an electrical operating day. Each 30-boiler operating startup, whichever is later. For an output-based emission standard in day rolling average emission rate is the existing unit, complete the initial Table 1 or 2 to this subpart, you must average of all of the valid SO2 emission performance evaluation no later than install, certify, operate, and maintain rates in the preceding 30 boiler October 13, 2015. the monitoring system and conduct on- operating days. (3) Collect PM CPMS hourly average going quality-assurance testing of the (4) Use only unadjusted, quality- output data for all boiler operating system according to part 75 of this assured SO2 concentration values in the hours except as indicated in paragraph chapter. Use only unadjusted, quality- emissions calculations; do not apply (h)(5) of this section. Express the PM assured flow rate data in the emissions bias adjustment factors to the part 75 CPMS output as milliamps, PM calculations. Do not apply bias SO2 data and do not use part 75 concentration, or other raw data signal adjustment factors to the flow rate data substitute data values. value. and do not use substitute flow rate data (g) If you use a Hg CEMS or a sorbent (4) Calculate the arithmetic 30-boiler in the calculations. trap monitoring system, you must operating day rolling average of all of (d) If you are required to make install, certify, operate, maintain and the hourly average PM CPMS output corrections for stack gas moisture quality-assure the data from the collected during all nonexempt boiler content when converting pollutant monitoring system in accordance with operating hours data (e.g., milliamps, concentrations to the units of an appendix A to this subpart. You must PM concentration, raw data signal).

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(5) You must collect data using the Continuous Emission Monitoring (ii) You must record and make PM CPMS at all times the process unit Systems at Stationary Sources in available upon request results of PM is operating and at the intervals Appendix B to part 60 of this chapter, CEMS system performance audits, dates specified in paragraph (h)(1)(ii) of this using Method 5 at Appendix A–3 to part and duration of periods when the PM section, except for periods of monitoring 60 of this chapter and ensuring that the CEMS is out of control to completion of system malfunctions, repairs associated front half filter temperature shall be the corrective actions necessary to with monitoring system malfunctions, 160° ± 14°C (320° ± 25°F). The return the PM CEMS to operation required monitoring system quality reportable measurement output from the consistent with your site-specific assurance or quality control activities PM CEMS must be expressed in units of monitoring plan. (including, as applicable, calibration the applicable emissions limit (e.g., lb/ (j) You may choose to comply with checks and required zero and span MMBtu, lb/MWh). the metal HAP emissions limits using adjustments), and any scheduled (2) Operate and maintain your PM CEMS approved in accordance with maintenance as defined in your site- CEMS according to the procedures and § 63.7(f) as an alternative to the specific monitoring plan. requirements in Procedure 2—Quality performance test method specified in (6) You must use all the data collected Assurance Requirements for Particulate this rule. If approved to use a HAP during all boiler operating hours in Matter Continuous Emission Monitoring metals CEMS, the compliance limit will assessing the compliance with your Systems at Stationary Sources in be expressed as a 30-boiler operating operating limit except: Appendix F to part 60 of this chapter. day rolling average of the numerical (i) Any data collected during (i) You must conduct the relative emissions limit value applicable for monitoring system malfunctions, repairs response audit (RRA) for your PM CEMS your unit in tables 1 or 2. If approved, associated with monitoring system at least once annually. you may choose to install, certify, malfunctions, or required monitoring (ii) You must conduct the relative operate, and maintain a HAP metals system quality assurance or quality correlation audit (RCA) for your PM CEMS and record the output of the HAP control activities conducted during CEMS at least once every 3 years. metals CEMS as specified in paragraphs monitoring system malfunctions are not (3) Collect PM CEMS hourly average (j)(1) through (5) of this section. used in calculations (report any such output data for all boiler operating (1)(i) Install and certify your HAP periods in your annual deviation hours except as indicated in paragraph metals CEMS according to the report); (i) of this section. procedures and requirements in you (ii) Any data collected during periods (4) Calculate the arithmetic 30-boiler approved site specific test plan as when the monitoring system is out of operating day rolling average of all of required in § 63.7(e). The reportable control as specified in your site-specific the hourly average PM CEMS output measurement output from the HAP monitoring plan, repairs associated with data collected during all nonexempt metals CEMS must be expressed in units periods when the monitoring system is boiler operating hours. of the applicable emissions limit (e.g., out of control, or required monitoring (5) You must collect data using the lb/MMBtu, lb/MWh) and in the form of system quality assurance or quality PM CEMS at all times the process unit a 30-boiler operating day rolling control activities conducted during out- is operating and at the intervals average. of-control periods are not used in specified in paragraph (a) of this (ii) Operate and maintain your HAP calculations (report emissions or section, except for periods of monitoring metals CEMS according to the operating levels and report any such system malfunctions, repairs associated procedures and criteria in your site periods in your annual deviation with monitoring system malfunctions, specific performance evaluation and report); and required monitoring system quality quality control program plan required in (iii) Any data recorded during periods assurance or quality control activities. § 63.8(d). of startup or shutdown. (i) You must use all the data collected (2) Collect HAP metals CEMS hourly (7) You must record and make during all boiler operating hours in average output data for all boiler available upon request results of PM assessing the compliance with your operating hours except as indicated in CPMS system performance audits, as operating limit except: section (j)(4) of this section. well as the dates and duration of (A) Any data collected during (3) Calculate the arithmetic 30-boiler periods from when the PM CPMS is out monitoring system malfunctions, repairs operating day rolling average of all of of control until completion of the associated with monitoring system the hourly average HAP metals CEMS corrective actions necessary to return malfunctions, or required monitoring output data collected during all the PM CPMS to operation consistent system quality assurance or control nonexempt boiler operating hours data. with your site-specific monitoring plan. activities conducted during monitoring (4) You must collect data using the (i) If you choose to comply with the system malfunctions in calculations and HAP metals CEMS at all times the PM filterable emissions limit in lieu of report any such periods in your annual process unit is operating and at the metal HAP limits, you may choose to deviation report; intervals specified in paragraph (a) of install, certify, operate, and maintain a (B) Any data collected during periods this section, except for periods of PM CEMS and record the output of the when the monitoring system is out of monitoring system malfunctions, repairs PM CEMS as specified in paragraphs control as specified in your site-specific associated with monitoring system (i)(1) through (5) of this section. The monitoring plan, repairs associated with malfunctions, and required monitoring compliance limit will be expressed as a periods when the monitoring system is system quality assurance or quality 30-boiler operating day rolling average out of control, or required monitoring control activities. of the numerical emissions limit value system quality assurance or control (i) You must use all the data collected applicable for your unit in tables 1 or 2 activities conducted during out of during all boiler operating hours in to this subpart. control periods in calculations used to assessing the compliance with your (1) Install and certify your PM CEMS report emissions or operating levels and emission limit except: according to the procedures and report any such periods in your annual (A) Any data collected during requirements in Performance deviation report; monitoring system malfunctions, repairs Specification 11—Specifications and (C) Any data recorded during periods associated with monitoring system Test Procedures for Particulate Matter of startup or shutdown. malfunctions, or required monitoring

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system quality assurance or control emission rate obtained with certified control activities, including, as activities conducted during monitoring CEMS after the applicable date in applicable, calibration checks and system malfunctions in calculations and § 63.9984 (or, if applicable, prior to that required zero and span adjustments. report any such periods in your annual date, as described in § 63.10005(b)(2)), You are required to affect monitoring deviation report; expressed in units of the standard, is the system repairs in response to (B) Any data collected during periods initial performance test. Initial monitoring system malfunctions and to when the monitoring system is out of compliance is demonstrated if the return the monitoring system to control as specified in your site-specific results of the performance test meet the operation as expeditiously as monitoring plan, repairs associated with applicable emission limit in Table 1 or practicable. periods when the monitoring system is 2 to this subpart. (c) You may not use data recorded out of control, or required monitoring (2) For a unit that uses a CEMS to during EGU startup or shutdown or system quality assurance or control measure SO2 or PM emissions for initial monitoring system malfunctions or activities conducted during out of compliance, the first 30 boiler operating monitoring system out-of-control control periods in calculations used to day average emission rate obtained with periods, repairs associated with report emissions or operating levels and certified CEMS after the applicable date monitoring system malfunctions or report any such periods in your annual in § 63.9984 (or, if applicable, prior to monitoring system out-of-control deviation report; that date, as described in periods, or required monitoring system (C) Any data recorded during periods § 63.10005(b)(2)), expressed in units of quality assurance or control activities in of startup or shutdown. the standard, is the initial performance calculations used to report emissions or (ii) You must record and make test. Initial compliance is demonstrated operating levels. You must use all the available upon request results of HAP if the results of the performance test data collected during all other periods metals CEMS system performance meet the applicable SO2 or filterable PM in assessing the operation of the control audits, dates and duration of periods emission limit in Table 1 or 2 to this device and associated control system. when the HAP metals CEMS is out of subpart. (d) Except for periods of monitoring control to completion of the corrective (d) For candidate LEE units, use the system malfunctions or monitoring actions necessary to return the HAP results of the performance testing system out-of-control periods, repairs metals CEMS to operation consistent described in § 63.10005(h) to determine associated with monitoring system with your site-specific performance initial compliance with the applicable malfunctions or monitoring system out- evaluation and quality control program emission limit(s) in Table 1 or 2 to this of-control periods, and required plan. subpart and to determine whether the (k) If you demonstrate compliance unit qualifies for LEE status. monitoring system quality assurance or with the HCl and HF emission limits for (e) You must submit a Notification of quality control activities including, as a liquid oil-fired EGU by conducting Compliance Status containing the applicable, calibration checks and quarterly testing, you must also develop results of the initial compliance required zero and span adjustments), a site-specific monitoring plan as demonstration, according to failure to collect required data is a provided for in § 63.10000(c)(2)(iii) and § 63.10030(e). deviation of the monitoring Table 7 to this subpart. (f)(1) You must determine the fuel requirements. whose combustion produces the least § 63.10021 How do I demonstrate § 63.10011 How do I demonstrate initial uncontrolled emissions, i.e., the continuous compliance with the emission compliance with the emissions limits and cleanest fuel, either natural gas or limitations, operating limits, and work work practice standards? distillate oil, that is available on site or practice standards? (a) You must demonstrate initial accessible nearby for use during periods (a) You must demonstrate continuous compliance with each emissions limit of startup or shutdown. that applies to you by conducting (2) Your cleanest fuel, either natural compliance with each emissions limit, performance testing. gas or distillate oil, for use during operating limit, and work practice (b) If you are subject to an operating periods of startup or shutdown standard in Tables 1 through 4 to this limit in Table 4 to this subpart, you determination may take safety subpart that applies to you, according to demonstrate initial compliance with considerations into account. the monitoring specified in Tables 6 and HAP metals or filterable PM emission (g) You must follow the startup or 7 to this subpart and paragraphs (b) limit(s) through performance stack tests shutdown requirements given in Table 3 through (g) of this section. and you elect to use a PM CPMS to for each coal-fired, liquid oil-fired, and (b) Except as otherwise provided in demonstrate continuous performance, or solid oil-derived fuel-fired EGU. § 63.10020(c), if you use a CEMS to if, for a liquid oil-fired unit, and you use measure SO2, PM, HCl, HF, or Hg quarterly stack testing for HCl and HF Continuous Compliance Requirements emissions, or using a sorbent trap plus site-specific parameter monitoring § 63.10020 How do I monitor and collect monitoring system to measure Hg to demonstrate continuous performance, data to demonstrate continuous emissions, you must demonstrate you must also establish a site-specific compliance? continuous compliance by using all operating limit, in accordance with (a) You must monitor and collect data quality-assured hourly data recorded by Table 4 to this subpart, § 63.10007, and according to this section and the site- the CEMS (or sorbent trap monitoring Table 6 to this subpart. You may use specific monitoring plan required by system) and the other required only the parametric data recorded § 63.10000(d). monitoring systems (e.g., flow rate, CO2, during successful performance tests (b) You must operate the monitoring O2, or moisture systems) to calculate the (i.e., tests that demonstrate compliance system and collect data at all required arithmetic average emissions rate in with the applicable emissions limits) to intervals at all times that the affected units of the standard on a continuous establish an operating limit. EGU is operating, except for periods of 30-boiler operating day rolling average (c)(1) If you use CEMS or sorbent trap monitoring system malfunctions or out- basis, updated at the end of each new monitoring systems to measure a HAP of-control periods (see § 63.8(c)(7) of boiler operating day. Use Equation 8 to (e.g., Hg or HCl) directly, the first 30- this part), and required monitoring determine the 30-boiler operating day boiler operating day rolling average system quality assurance or quality rolling average.

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Where: must record the PM CPMS output data arithmetic average operating parameter Heri is the hourly emissions rate for hour i for all periods when the process is in units of the operating limit (e.g., and n is the number of hourly emissions operating and the PM CPMS is not out- milliamps, PM concentration, raw data rate values collected over 30 boiler of-control. You must demonstrate signal) on a 30 operating day rolling operating days. continuous compliance by using all average basis, updated at the end of (c) If you use a PM CPMS data to quality-assured hourly average data each new boiler operating day. Use measure compliance with an operating collected by the PM CPMS for all Equation 9 to determine the 30 boiler limit in Table 4 to this subpart, you operating hours to calculate the operating day average.

Where: replace any components of the burner or dampers to ensure that the systems are Hpvi is the hourly parameter value for hour combustion controls as necessary upon operated as designed. Any component i and n is the number of valid hourly initiation of the work practice program out of calibration, in or near failure, or parameter values collected over 30 boiler and at least once every required in a state that is likely to negate operating days. inspection period. Repair of a burner or combustion optimization efforts prior to (d) If you use quarterly performance combustion control component the next tune-up, should be corrected or testing to demonstrate compliance with requiring special order parts may be repaired as necessary; one or more applicable emissions limits scheduled as follows: (6) Optimize combustion to minimize in Table 1 or 2 to this subpart, you (i) Burner or combustion control generation of CO and NOX. This (1) May skip performance testing in component parts needing replacement optimization should be consistent with those quarters during which less than that affect the ability to optimize NOX the manufacturer’s specifications, if 168 boiler operating hours occur, except and CO must be installed within 3 available, or best combustion that a performance test must be calendar months after the burner engineering practice for the applicable conducted at least once every calendar inspection, burner type. NOX optimization includes year. (ii) Burner or combustion control burners, overfire air controls, concentric (2) Must conduct the performance test component parts that do not affect the firing system improvements, neural as defined in Table 5 to this subpart and ability to optimize NOX and CO may be network or combustion efficiency calculate the results of the testing in installed on a schedule determined by software, control systems calibrations, units of the applicable emissions the operator; adjusting combustion zone temperature (2) As applicable, inspect the flame standard; and profiles, and add-on controls such as (3) Must conduct site-specific pattern and make any adjustments to the SCR and SNCR; CO optimization monitoring for a liquid oil-fired unit to burner or combustion controls necessary includes burners, overfire air controls, ensure compliance with the HCl and HF to optimize the flame pattern. The concentric firing system improvements, emission limits in Tables 1 and 2 to this adjustment should be consistent with neural network or combustion efficiency subpart, in accordance with the the manufacturer’s specifications, if requirements of § 63.10000(c)(2)(iii). available, or in accordance with best software, control systems calibrations, The monitoring must meet the general combustion engineering practice for that and adjusting combustion zone operating requirements provided in burner type; temperature profiles; § 63.10020(a). (3) As applicable, observe the damper (7) While operating at full load or the (e) If you must conduct periodic operations as a function of mill and/or predominantly operated load, measure performance tune-ups of your EGU(s), as cyclone loadings, cyclone and the concentration in the effluent stream specified in paragraphs (e)(1) through pulverizer coal feeder loadings, or other of CO and NOX in ppm, by volume, and (9) of this section, perform the first tune- pulverizer and coal mill performance oxygen in volume percent, before and up as part of your initial compliance parameters, making adjustments and after the tune-up adjustments are made demonstration. Notwithstanding this effecting repair to dampers, controls, (measurements may be either on a dry requirement, you may delay the first mills, pulverizers, cyclones, and or wet basis, as long as it is the same burner inspection until the next sensors; basis before and after the adjustments scheduled unit outage provided you (4) As applicable, evaluate windbox are made). You may use portable CO, meet the requirements of § 63.10005. pressures and air proportions, making NOX and O2 monitors for this Subsequently, you must perform an adjustments and effecting repair to measurement. EGU’s employing neural inspection of the burner at least once dampers, actuators, controls, and network optimization systems need only every 36 calendar months unless your sensors; provide a single pre- and post-tune-up EGU employs neural network (5) Inspect the system controlling the value rather than continual values combustion optimization during normal air-to-fuel ratio and ensure that it is before and after each optimization operations in which case you must correctly calibrated and functioning adjustment made by the system; perform an inspection of the burner and properly. Such inspection may include (8) Maintain on-site and submit, if combustion controls at least once every calibrating excess O2 probes and/or requested by the Administrator, an 48 calendar months. sensors, adjusting overfire air systems, annual report containing the (1) As applicable, inspect the burner changing software parameters, and information in paragraphs (e)(1) through and combustion controls, and clean or calibrating associated actuators and (e)(9) of this section including:

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(i) The concentrations of CO and NOX (i) You must provide reports as operating limit determined in in the effluent stream in ppm by specified in § 63.10031 concerning paragraphs (a) and (b) of this section. volume, and oxygen in volume percent, activities and periods of startup and Notification, Reports, and Records measured before and after an adjustment shutdown. of the EGU combustion systems; § 63.10030 What notifications must I (ii) A description of any corrective § 63.10022 How do I demonstrate submit and when? continuous compliance under the actions taken as a part of the emissions averaging provision? (a) You must submit all of the combustion adjustment; and notifications in §§ 63.7(b) and (c), 63.8 (a) Following the compliance date, the (iii) The type(s) and amount(s) of fuel (e), (f)(4) and (6), and 63.9 (b) through owner or operator must demonstrate used over the 12 calendar months prior (h) that apply to you by the dates compliance with this subpart on a to an adjustment, but only if the unit specified. continuous basis by meeting the was physically and legally capable of (b) As specified in § 63.9(b)(2), if you requirements of paragraphs (a)(1) using more than one type of fuel during startup your affected source before April through (3) of this section. that period; and 16, 2012, you must submit an Initial (1) For each calendar month, (9) Report the dates of the initial and Notification not later than 120 days after demonstrate compliance with the subsequent tune-ups as follows: April 16, 2012. average weighted emissions limit for the (i) If the first required tune-up is (c) As specified in § 63.9(b)(4) and existing units participating in the performed as part of the initial (b)(5), if you startup your new or emissions averaging option as compliance demonstration, report the reconstructed affected source on or after determined in § 63.10009(f) and (g); date of the tune-up in hard copy (as April 16, 2012, you must submit an (2) For each existing unit participating specified in § 63.10030) and Initial Notification not later than 15 in the emissions averaging option that is electronically (as specified in days after the actual date of startup of equipped with PM CPMS, maintain the § 63.10031). Report the date of each the affected source. average parameter value at or below the subsequent tune-up electronically (as (d) When you are required to conduct operating limit established during the specified in § 63.10031). a performance test, you must submit a most recent performance test; Notification of Intent to conduct a (ii) If the first tune-up is not (3) For each existing unit participating performance test at least 30 days before conducted as part of the initial in the emissions averaging option the performance test is scheduled to compliance demonstration, but is venting to a common stack begin. postponed until the next unit outage, configuration containing affected units (e) When you are required to conduct report the date of that tune-up and all from other subcategories, maintain the an initial compliance demonstration as subsequent tune-ups electronically, in appropriate operating limit for each unit specified in § 63.10011(a), you must accordance with § 63.10031. as specified in Table 4 to this subpart submit a Notification of Compliance (f) You must submit the reports that applies. Status according to § 63.9(h)(2)(ii). The required under § 63.10031 and, if (b) Any instance where the owner or Notification of Compliance Status report applicable, the reports required under operator fails to comply with the must contain all the information appendices A and B to this subpart. The continuous monitoring requirements in specified in paragraphs (e)(1) through electronic reports required by paragraphs (a)(1) through (3) of this (7), as applicable. appendices A and B to this subpart must section is a deviation. (1) A description of the affected be sent to the Administrator source(s) including identification of electronically in a format prescribed by § 63.10023 How do I establish my PM which subcategory the source is in, the the Administrator, as provided in CPMS operating limit and determine design capacity of the source, a § 63.10031. CEMS data (except for PM compliance with it? description of the add-on controls used CEMS and any approved alternative (a) During the initial performance test on the source, description of the fuel(s) monitoring using a HAP metals CEMS) or any such subsequent performance burned, including whether the fuel(s) shall be submitted using EPA’s test that demonstrates compliance with were determined by you or EPA through Emissions Collection and Monitoring the filterable PM, individual non- a petition process to be a non-waste Plan System (ECMPS) Client Tool. Other mercury HAP metals, or total non- under 40 CFR 241.3, whether the fuel(s) data, including PM CEMS data, HAP mercury HAP metals limit (or for liquid were processed from discarded non- metals CEMS data, and CEMS oil-fired units, individual HAP metals or hazardous secondary materials within performance test detail reports, shall be total HAP metals limit, including Hg) in the meaning of 40 CFR 241.3, and submitted in the file format generated Table 1 or 2, record all hourly average justification for the selection of fuel(s) through use of EPA’s Electronic output values (e.g., milliamps, stack burned during the performance test. Reporting Tool, the Compliance and concentration, or other raw data signal) (2) Summary of the results of all Emissions Data Reporting Interface, or from the PM CPMS for the periods performance tests and fuel analyses and alternate electronic file format, all as corresponding to the test runs (e.g., nine calculations conducted to demonstrate provided for under § 63.10031. 1-hour average PM CPMS output values initial compliance including all (g) You must report each instance in for three 3-hour test runs). established operating limits. which you did not meet an applicable (b) Determine your operating limit as (3) Identification of whether you plan emissions limit or operating limit in the highest 1-hour average PM CPMS to demonstrate compliance with each Tables 1 through 4 to this subpart or output value recorded during the applicable emission limit through failed to conduct a required tune-up. performance test. You must verify an performance testing; fuel moisture These instances are deviations from the existing or establish a new operating analyses; performance testing with requirements of this subpart. These limit after each repeated performance operating limits (e.g., use of PM CPMS); deviations must be reported according test. CEMS; or a sorbent trap monitoring to § 63.10031. (c) You must operate and maintain system. (h) You must keep records as your process and control equipment (4) Identification of whether you plan specified in § 63.10032 during periods such that the 30 operating day average to demonstrate compliance by emissions of startup and shutdown. PM CPMS output does not exceed the averaging.

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(5) A signed certification that you electronically no later than July 31 or compliance report specified in section have met all applicable emission limits January 31, whichever date is the first (c). and work practice standards. date following the end of the first (e) Each affected source that has (6) If you had a deviation from any calendar half after the compliance date obtained a Title V operating permit emission limit, work practice standard, that is specified for your source in pursuant to part 70 or part 71 of this or operating limit, you must also submit § 63.9984. chapter must report all deviations as a brief description of the deviation, the (3) Each subsequent compliance defined in this subpart in the duration of the deviation, emissions report must cover the semiannual semiannual monitoring report required point identification, and the cause of the reporting period from January 1 through by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR deviation in the Notification of June 30 or the semiannual reporting 71.6(a)(3)(iii)(A). If an affected source Compliance Status report. period from July 1 through December submits a compliance report pursuant to (7) In addition to the information 31. Table 8 to this subpart along with, or as required in § 63.9(h)(2), your (4) Each subsequent compliance part of, the semiannual monitoring notification of compliance status must report must be postmarked or submitted report required by 40 CFR include the following: electronically no later than July 31 or 70.6(a)(3)(iii)(A) or 40 CFR (i) A summary of the results of the January 31, whichever date is the first 71.6(a)(3)(iii)(A), and the compliance annual performance tests and date following the end of the report includes all required information documentation of any operating limits semiannual reporting period. concerning deviations from any that were reestablished during this test, (5) For each affected source that is emission limit, operating limit, or work if applicable. If you are conducting stack subject to permitting regulations practice requirement in this subpart, tests once every 3 years consistent with pursuant to part 70 or part 71 of this submission of the compliance report § 63.10006(i), the date of the last three chapter, and if the permitting authority satisfies any obligation to report the stack tests, a comparison of the emission has established dates for submitting same deviations in the semiannual level you achieved in the last three stack semiannual reports pursuant to 40 CFR monitoring report. Submission of a tests to the 50 percent emission limit 70.6(a)(3)(iii)(A) or 40 CFR compliance report does not otherwise threshold required in § 63.10006(i), and 71.6(a)(3)(iii)(A), you may submit the affect any obligation the affected source a statement as to whether there have first and subsequent compliance reports may have to report deviations from been any operational changes since the according to the dates the permitting permit requirements to the permit last stack test that could increase authority has established instead of authority. (f) As of January 1, 2012, and within emissions. according to the dates in paragraphs 60 days after the date of completing (ii) Certifications of compliance, as (b)(1) through (4) of this section. applicable, and must be signed by a each performance test, you must submit (c) The compliance report must the results of the performance tests responsible official stating: contain the information required in (A) ‘‘This EGU complies with the required by this subpart to EPA’s paragraphs (c)(1) through (4) of this WebFIRE database by using the requirements in § 63.10021(a) to section. demonstrate continuous compliance.’’ Compliance and Emissions Data (1) The information required by the Reporting Interface (CEDRI) that is and summary report located in (B) ‘‘No secondary materials that are accessed through EPA’s Central Data 63.10(e)(3)(vi). Exchange (CDX) (www.epa.gov/cdx). solid waste were combusted in any (2) The total fuel use by each affected affected unit.’’ Performance test data must be submitted source subject to an emission limit, for in the file format generated through use § 63.10031 What reports must I submit and each calendar month within the of EPA’s Electronic Reporting Tool when? semiannual reporting period, including, (ERT) (see http://www.epa.gov/ttn/chief/ (a) You must submit each report in but not limited to, a description of the ert/index.html). Only data collected Table 8 to this subpart that applies to fuel, whether the fuel has received a using those test methods on the ERT you. If you are required to (or elect to) non-waste determination by EPA or Web site are subject to this requirement continuously monitor Hg and/or HCl your basis for concluding that the fuel for submitting reports electronically to and/or HF emissions, you must also is not a waste, and the total fuel usage WebFIRE. Owners or operators who submit the electronic reports required amount with units of measure. claim that some of the information being under appendix A and/or appendix B to (3) Indicate whether you burned new submitted for performance tests is the subpart, at the specified frequency. types of fuel during the reporting confidential business information (CBI) (b) Unless the Administrator has period. If you did burn new types of fuel must submit a complete ERT file approved a different schedule for you must include the date of the including information claimed to be CBI submission of reports under § 63.10(a), performance test where that fuel was in on a compact disk or other commonly you must submit each report by the date use. used electronic storage media in Table 8 to this subpart and according (4) Include the date of the most recent (including, but not limited to, flash to the requirements in paragraphs (b)(1) tune-up for each unit subject to the drives) to EPA. The electronic media through (5) of this section. requirement to conduct a performance must be clearly marked as CBI and (1) The first compliance report must tune-up according to § 63.10021(e). mailed to U.S. EPA/OAPQS/CORE CBI cover the period beginning on the Include the date of the most recent Office, Attention: WebFIRE compliance date that is specified for burner inspection if it was not done Administrator, MD C404–02, 4930 Old your affected source in § 63.9984 and annually and was delayed until the next Page Rd., Durham, NC 27703. The same ending on June 30 or December 31, scheduled unit shutdown. ERT file with the CBI omitted must be whichever date is the first date that (d) For each excess emissions submitted to EPA via CDX as described occurs at least 180 days after the occurring at an affected source where earlier in this paragraph. At the compliance date that is specified for you are using a CMS to comply with discretion of the delegated authority, your source in § 63.9984. that emission limit or operating limit, you must also submit these reports, (2) The first compliance report must you must include the information including the confidential business be postmarked or submitted required in § 63.10(e)(3)(v) in the information, to the delegated authority

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in the format specified by the delegated operating day rolling average values evaluations, as required in authority. derived from the CEMS and PM CPMS. § 63.10(b)(2)(viii). (1) Within 60 days after the date of (3) Reports for an SO2 CEMS, a Hg (b) For each CEMS and CPMS, you completing each CEMS (SO2, PM, HCl, CEMS or sorbent trap monitoring must keep records according to HF, and Hg) performance evaluation system, an HCl or HF CEMS, and any paragraphs (b)(1) through (4) of this test, as defined in § 63.2 and required by supporting monitors for such systems section. this subpart, you must submit the (such as a diluent or moisture monitor) (1) Records described in relative accuracy test audit (RATA) data shall be submitted using the ECMPS § 63.10(b)(2)(vi) through (xi). (or, for PM CEMS, RCA and RRA data) Client Tool, as provided for in (2) Previous (i.e., superseded) required by this subpart to EPA’s Appendices A and B to this subpart and versions of the performance evaluation WebFIRE database by using the § 63.10021(f). plan as required in § 63.8(d)(3). Compliance and Emissions Data (4) Submit the compliance reports (3) Request for alternatives to relative Reporting Interface (CEDRI) that is required under paragraphs (c) and (d) of accuracy test for CEMS as required in accessed through EPA’s Central Data this section and the notification of § 63.8(f)(6)(i). (4) Records of the date and time that Exchange (CDX) (www.epa.gov/cdx). compliance status required under each deviation started and stopped, and The RATA data shall be submitted in § 63.10030(e) to EPA’s WebFIRE whether the deviation occurred during a the file format generated through use of database by using the Compliance and period of startup, shutdown, or EPA’s Electronic Reporting Tool (ERT) Emissions Data Reporting Interface (CEDRI) that is accessed through EPA’s malfunction or during another period. (http://www.epa.gov/ttn/chief/ert/ (c) You must keep the records index.html). Only RATA data Central Data Exchange (CDX) (www.epa.gov/cdx). You must use the required in Table 7 to this subpart compounds listed on the ERT Web site including records of all monitoring data are subject to this requirement. Owners appropriate electronic reporting form in CEDRI or provide an alternate electronic and calculated averages for applicable or operators who claim that some of the PM CPMS operating limits to show information being submitted for RATAs file consistent with EPA’s reporting form output format. continuous compliance with each is confidential business information emission limit and operating limit that (CBI) shall submit a complete ERT file (5) All reports required by this subpart not subject to the requirements applies to you. including information claimed to be CBI (d) For each EGU subject to an on a compact disk or other commonly in paragraphs (f)(1) through (4) of this section must be sent to the emission limit, you must also keep the used electronic storage media records in paragraphs (d)(1) through (3) (including, but not limited to, flash Administrator at the appropriate address listed in § 63.13. If acceptable to of this section. drives) by registered letter to EPA and (1) You must keep records of monthly the same ERT file with the CBI omitted both the Administrator and the owner or operator of a source, these reports may fuel use by each EGU, including the to EPA via CDX as described earlier in type(s) of fuel and amount(s) used. this paragraph. The compact disk or be submitted on electronic media. The Administrator retains the right to (2) If you combust non-hazardous other commonly used electronic storage secondary materials that have been media shall be clearly marked as CBI require submittal of reports subject to paragraphs (f)(1), (2), and (3) of this determined not to be solid waste and mailed to U.S. EPA/OAPQS/CORE pursuant to 40 CFR 241.3(b)(1), you CBI Office, Attention: WebFIRE section in paper format. (g) If you had a malfunction during must keep a record which documents Administrator, MD C404–02, 4930 Old how the secondary material meets each Page Rd., Durham, NC 27703. At the the reporting period, the compliance report must include the number, of the legitimacy criteria. If you combust discretion of the delegated authority, a fuel that has been processed from a owners or operators shall also submit duration, and a brief description for each type of malfunction which discarded non-hazardous secondary these RATAs to the delegated authority material pursuant to 40 CFR 241.3(b)(2), in the format specified by the delegated occurred during the reporting period and which caused or may have caused you must keep records as to how the authority. Owners or operators shall operations that produced the fuel submit calibration error testing, drift any applicable emission limitation to be exceeded. satisfies the definition of processing in checks, and other information required 40 CFR 241.2. If the fuel received a non- in the performance evaluation as § 63.10032 What records must I keep? waste determination pursuant to the described in § 63.2 and as required in (a) You must keep records according petition process submitted under 40 this chapter. to paragraphs (a)(1) and (2) of this CFR 241.3(c), you must keep a record (2) For a PM CEMS, PM CPMS, or section. If you are required to (or elect which documents how the fuel satisfies approved alternative monitoring using a to) continuously monitor Hg and/or HCl the requirements of the petition process. HAP metals CEMS, within 60 days after and/or HF emissions, you must also (3) For an EGU that qualifies as an the reporting periods ending on March keep the records required under LEE under § 63.10005(h), you must keep 31st, June 30th, September 30th, and appendix A and/or appendix B to this annual records that document that your December 31st, you must submit subpart. emissions in the previous stack test(s) quarterly reports to EPA’s WebFIRE (1) A copy of each notification and continue to qualify the unit for LEE database by using the Compliance and report that you submitted to comply status for an applicable pollutant, and Emissions Data Reporting Interface with this subpart, including all document that there was no change in (CEDRI) that is accessed through EPA’s documentation supporting any Initial source operations including fuel Central Data Exchange (CDX) Notification or Notification of composition and operation of air (www.epa.gov/cdx). You must use the Compliance Status or semiannual pollution control equipment that would appropriate electronic reporting form in compliance report that you submitted, cause emissions of the pollutant to CEDRI or provide an alternate electronic according to the requirements in increase within the past year. file consistent with EPA’s reporting § 63.10(b)(2)(xiv). (e) If you elect to average emissions form output format. For each reporting (2) Records of performance stack tests, consistent with § 63.10009, you must period, the quarterly reports must fuel analyses, or other compliance additionally keep a copy of the include all of the calculated 30-boiler demonstrations and performance emissions averaging implementation

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plan required in § 63.10009(g), all this subpart. You should contact your for the fuel to be combusted the entire calculations required under § 63.10009, EPA Regional Office to find out if this 24-hour period. including daily records of heat input or subpart is delegated to your state, local, Capacity factor for a liquid oil-fired steam generation, as applicable, and or tribal agency. EGU means the total annual heat input monitoring records consistent with (b) In delegating implementation and from oil divided by the product of § 63.10022. enforcement authority of this subpart to maximum hourly heat input for the (f) You must keep records of the a state, local, or tribal agency under 40 EGU, regardless of fuel, multiplied by occurrence and duration of each startup CFR part 63, subpart E, the authorities 8,760 hours. and/or shutdown. listed in paragraphs (b)(1) through (4) of Coal means all solid fuels classifiable (g) You must keep records of the this section are retained by the EPA as anthracite, bituminous, sub- occurrence and duration of each Administrator and are not transferred to bituminous, or lignite by ASTM Method malfunction of an operation (i.e., the state, local, or tribal agency; D388–05, ‘‘Standard Classification of process equipment) or the air pollution moreover, the U.S. EPA retains Coals by Rank’’ (incorporated by control and monitoring equipment. oversight of this subpart and can take reference, see § 63.14), and coal refuse. (h) You must keep records of actions enforcement actions, as appropriate, Synthetic fuels derived from coal for the taken during periods of malfunction to with respect to any failure by any purpose of creating useful heat minimize emissions in accordance with person to comply with any provision of including but not limited to, coal § 63.10000(b), including corrective this subpart. derived gases (not meeting the actions to restore malfunctioning (1) Approval of alternatives to the definition of natural gas), solvent- process and air pollution control and non-opacity emission limits and work refined coal, coal-oil mixtures, and coal- monitoring equipment to its normal or practice standards in § 63.9991(a) and water mixtures, are considered ‘‘coal’’ usual manner of operation. (b) under § 63.6(g). for the purposes of this subpart. (i) You must keep records of the (2) Approval of major change to test Coal-fired electric utility steam type(s) and amount(s) of fuel used methods in Table 5 to this subpart generating unit means an electric utility during each startup or shutdown. under § 63.7(e)(2)(ii) and (f) and as steam generating unit meeting the (j) If you elect to establish that an EGU defined in § 63.90, approval of minor definition of ‘‘fossil fuel-fired’’ that qualifies as a limited-use liquid oil-fired and intermediate changes to monitoring burns coal for more than 10.0 percent of EGU, you must keep records of the performance specifications/procedures the average annual heat input during type(s) and amount(s) of fuel use in each in Table 5 where the monitoring serves any 3 consecutive calendar years or for calendar quarter to document that the as the performance test method (see more than 15.0 percent of the annual capacity factor limitation for that definition of ‘‘test method’’ in § 63.2. heat input during any one calendar year. subcategory is met. (3) Approval of major changes to Coal refuse means any by-product of monitoring under § 63.8(f) and as coal mining, physical coal cleaning, and § 63.10033 In what form and how long defined in § 63.90. coal preparation operations (e.g., culm, must I keep my records? (4) Approval of major change to gob, etc.) containing coal, matrix (a) Your records must be in a form recordkeeping and reporting under material, clay, and other organic and suitable and readily available for § 63.10(e) and as defined in § 63.90. inorganic material with an ash content expeditious review, according to greater than 50 percent (by weight) and § 63.10(b)(1). § 63.10042 What definitions apply to this a heating value less than 13,900 (b) As specified in § 63.10(b)(1), you subpart? kilojoules per kilogram (6,000 Btu per must keep each record for 5 years Terms used in this subpart are pound) on a dry basis. following the date of each occurrence, defined in the Clean Air Act (CAA), in Cogeneration means a steam- measurement, maintenance, corrective § 63.2 (the General Provisions), and in generating unit that simultaneously action, report, or record. this section as follows: produces both electrical and useful (c) You must keep each record on site Affirmative defense means, in the thermal (or mechanical) energy from the for at least 2 years after the date of each context of an enforcement proceeding, a same primary energy source. occurrence, measurement, maintenance, response or defense put forward by a Cogeneration unit means a stationary, corrective action, report, or record, defendant, regarding which the fossil fuel-fired EGU meeting the according to § 63.10(b)(1). You can keep defendant has the burden of proof, and definition of ‘‘fossil fuel-fired’’ or the records off site for the remaining 3 the merits of which are independently stationary, integrated gasification years. and objectively evaluated in a judicial combined cycle: or administrative proceeding. Other Requirements and Information (1) Having equipment used to produce Anthracite coal means solid fossil fuel electricity and useful thermal energy for § 63.10040 What parts of the General classified as anthracite coal by industrial, commercial, heating, or Provisions apply to me? American Society of Testing and cooling purposes through the sequential Table 9 to this subpart shows which Materials (ASTM) Method D388–05, use of energy; and parts of the General Provisions in ‘‘Standard Classification of Coals by (2) Producing during the 12-month §§ 63.1 through 63.15 apply to you. Rank’’ (incorporated by reference, see period starting on the date the unit first § 63.14). produces electricity and during any § 63.10041 Who implements and enforces Bituminous coal means coal that is calendar year after which the unit first this subpart? classified as bituminous according to produces electricity: (a) This subpart can be implemented ASTM Method D388–05, ‘‘Standard (i) For a topping-cycle cogeneration and enforced by U.S. EPA, or a Classification of Coals by Rank’’ unit, delegated authority such as your state, (incorporated by reference, see § 63.14). (A) Useful thermal energy not less local, or tribal agency. If the EPA Boiler operating day means a 24-hour than 5 percent of total energy output; Administrator has delegated authority to period between midnight and the and your state, local, or tribal agency, then following midnight during which any (B) Useful power that, when added to that agency (as well as the U.S. EPA) has fuel is combusted at any time in the one-half of useful thermal energy the authority to implement and enforce steam generating unit. It is not necessary produced, is not less than 42.5 percent

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of total energy input, if useful thermal combustors (FBC) or circulating Fossil fuel means natural gas, oil, energy produced is 15 percent or more fluidized bed (CFB) boilers are included coal, and any form of solid, liquid, or of total energy output, or not less than in this definition. gaseous fuel derived from such material. 45 percent of total energy input, if Dry sorbent injection (DSI) means an Fossil fuel-fired means an electric useful thermal energy produced is less add-on air pollution control system in utility steam generating unit (EGU) that than 15 percent of total energy output. which sorbent (e.g., conventional is capable of combusting more than 25 (ii) For a bottoming-cycle activated carbon, brominated activated MW of fossil fuels. To be ‘‘capable of cogeneration unit, useful power not less carbon, Trona, hydrated lime, sodium combusting’’ fossil fuels, an EGU would than 45 percent of total energy input. carbonate, etc.) is injected into the flue need to have these fuels allowed in its (3) Provided that the total energy gas steam upstream of a PM control operating permit and have the input under paragraphs (2)(i)(B) and device to react with and neutralize acid appropriate fuel handling facilities on- (2)(ii) of this definition shall equal the gases (such as SO2 and HCl) or Hg in the site or otherwise available (e.g., coal unit’s total energy input from all fuel exhaust stream forming a dry powder handling equipment, including coal except biomass if the unit is a boiler. material that may be removed in a storage area, belts and conveyers, Combined-cycle gas stationary primary or secondary PM control pulverizers, etc.; oil storage facilities). In combustion turbine means a stationary device. addition, fossil fuel-fired means any combustion turbine system where heat Electric Steam generating unit means EGU that fired fossil fuels for more than from the turbine exhaust gases is any furnace, boiler, or other device used 10.0 percent of the average annual heat recovered by a waste heat boiler. for combusting fuel for the purpose of input during any 3 consecutive calendar Common stack means the exhaust of producing steam (including fossil-fuel- years or for more than 15.0 percent of emissions from two or more affected fired steam generators associated with the annual heat input during any one units through a single flue. integrated gasification combined cycle calendar year after the applicable Continental liquid oil-fired gas turbines; nuclear steam generators compliance date. subcategory means any oil-fired electric are not included) for the purpose of Fuel type means each category of fuels utility steam generating unit that burns powering a generator to produce that share a common name or liquid oil and is located in the electricity or electricity and other classification. Examples include, but are continental United States. thermal energy. not limited to, bituminous coal, Deviation. (1) Deviation means any Electric utility steam generating unit subbituminous coal, lignite, anthracite, instance in which an affected source (EGU) means a fossil fuel-fired biomass, and residual oil. Individual subject to this subpart, or an owner or combustion unit of more than 25 fuel types received from different operator of such a source: megawatts electric (MWe) that serves a suppliers are not considered new fuel (i) Fails to meet any requirement or generator that produces electricity for types. obligation established by this subpart sale. A fossil fuel-fired unit that Fluidized bed boiler, or fluidized bed including, but not limited to, any cogenerates steam and electricity and combustor, or circulating fluidized emission limit, operating limit, work supplies more than one-third of its boiler, or CFB means a boiler utilizing practice standard, or monitoring potential electric output capacity and a fluidized bed combustion process. requirement; or more than 25 MWe output to any utility Fluidized bed combustion means a (ii) Fails to meet any term or power distribution system for sale is process where a fuel is burned in a bed condition that is adopted to implement considered an electric utility steam of granulated particles which are an applicable requirement in this generating unit. maintained in a mobile suspension by subpart and that is included in the Emission limitation means any the upward flow of air and combustion operating permit for any affected source emissions limit, work practice standard, products. required to obtain such a permit. or operating limit. Gaseous fuel includes, but is not (2) A deviation is not always a Excess emissions means, with respect limited to, natural gas, process gas, violation. The determination of whether to this subpart, results of any required landfill gas, coal derived gas, solid oil- a deviation constitutes a violation of the measurements outside the applicable derived gas, refinery gas, and biogas. standard is up to the discretion of the range (e.g., emissions limitations, Generator means a device that entity responsible for enforcement of the parametric operating limits) that is produces electricity. standards. permitted by this subpart. The values of Gross output means the gross useful Distillate oil means fuel oils, measurements will be in the same units work performed by the steam generated including recycled oils, that comply and averaging time as the values and, for an IGCC electric utility steam with the specifications for fuel oil specified in this subpart for the generating unit, the work performed by numbers 1 and 2, as defined by ASTM limitations. the stationary combustion turbines. For Method D396–10, ‘‘Standard Federally enforceable means all a unit generating only electricity, the Specification for Fuel Oils’’ limitations and conditions that are gross useful work performed is the gross (incorporated by reference, see § 63.14). enforceable by the Administrator, electrical output from the unit’s turbine/ Dry flue gas desulfurization including the requirements of 40 CFR generator sets. For a cogeneration unit, technology, or dry FGD, or spray dryer parts 60, 61, and 63; requirements the gross useful work performed is the absorber (SDA), or spray dryer, or dry within any applicable state gross electrical output, including any scrubber means an add-on air pollution implementation plan; and any permit such electricity used in the power control system located downstream of requirements established under 40 CFR production process (which process the steam generating unit that injects a 52.21 or under 40 CFR 51.18 and 40 includes, but is not limited to, any on- dry alkaline sorbent (dry sorbent CFR 51.24. site processing or treatment of fuel injection) or sprays an alkaline sorbent Flue gas desulfurization system combusted at the unit and any on-site slurry (spray dryer) to react with and means any add-on air pollution control emission controls), or mechanical neutralize acid gases such as SO2 and system located downstream of the steam output plus 75 percent of the useful HCl in the exhaust stream forming a dry generating unit whose purpose or effect thermal output measured relative to ISO powder material. Alkaline sorbent is to remove at least 50 percent of the conditions that is not used to generate injection systems in fluidized bed SO2 in the exhaust gas stream. additional electrical or mechanical

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output or to enhance the performance of not include the following gaseous fuels: by ASTM Method D396–10, ‘‘Standard the unit (i.e., steam delivered to an landfill gas, digester gas, refinery gas, Specification for Fuel Oils’’ industrial process). sour gas, blast furnace gas, coal-derived (incorporated by reference, see § 63.14). Heat input means heat derived from gas, producer gas, coke oven gas, or any Responsible official means combustion of fuel in an EGU (synthetic gaseous fuel produced in a process responsible official as defined in 40 CFR gas for an IGCC) and does not include which might result in highly variable 70.2. the heat input from preheated sulfur content or heating value. Shutdown means the cessation of combustion air, recirculated flue gases, Natural gas-fired electric utility steam operation of a boiler for any purpose. or exhaust gases from other sources generating unit means an electric utility Shutdown begins either when none of such as gas turbines, internal steam generating unit meeting the the steam from the boiler is used to combustion engines, etc. definition of ‘‘fossil fuel-fired’’ that is generate electricity for sale over the grid Integrated gasification combined not a coal-fired, oil-fired, or IGCC or for any other purpose (including on- cycle electric utility steam generating electric utility steam generating unit and site use), or at the point of no fuel being unit or IGCC means an electric utility that burns natural gas for more than 10.0 fired in the boiler, whichever is earlier. steam generating unit meeting the percent of the average annual heat input Shutdown ends when there is both no definition of ‘‘fossil fuel-fired’’ that during any 3 consecutive calendar years electricity being generated and no fuel burns a synthetic gas derived from coal or for more than 15.0 percent of the being fired in the boiler. and/or solid oil-derived fuel for more annual heat input during any one Startup means either the first-ever than 10.0 percent of the average annual calendar year. firing of fuel in a boiler for the purpose heat input during any 3 consecutive Net-electric output means the gross of producing electricity, or the firing of calendar years or for more than 15.0 electric sales to the utility power fuel in a boiler after a shutdown event percent of the annual heat input during distribution system minus purchased for any purpose. Startup ends when any any one calendar year in a combined- power on a calendar year basis. of the steam from the boiler is used to cycle gas turbine. No solid coal or solid Non-continental area means the State generate electricity for sale over the grid oil-derived fuel is directly burned in the of Hawaii, the Virgin Islands, Guam, or for any other purpose (including on- unit during operation. American Samoa, the Commonwealth of site use). ISO conditions means a temperature Puerto Rico, or the Northern Mariana Stationary combustion turbine means of 288 Kelvin, a relative humidity of 60 Islands. all equipment, including but not limited percent, and a pressure of 101.3 Non-continental liquid oil-fired to the turbine, the fuel, air, lubrication kilopascals. subcategory means any oil-fired electric and exhaust gas systems, control Lignite coal means coal that is utility steam generating unit that burns systems (except emissions control classified as lignite A or B according to liquid oil and is located outside the equipment), and any ancillary ASTM Method D388–05, ‘‘Standard continental United States. Classification of Coals by Rank’’ Non-mercury (Hg) HAP metals means components and sub-components (incorporated by reference, see § 63.14). Antimony (Sb), Arsenic (As), Beryllium comprising any simple cycle stationary Limited-use liquid oil-fired (Be), Cadmium (Cd), Chromium (Cr), combustion turbine, any regenerative/ subcategory means an oil-fired electric Cobalt (Co), Lead (Pb), Manganese (Mn), recuperative cycle stationary utility steam generating unit with an Nickel (Ni), and Selenium (Se). Oil combustion turbine, the combustion annual capacity factor of less than 8 means crude oil or petroleum or a fuel turbine portion of any stationary percent of its maximum or nameplate derived from crude oil or petroleum, cogeneration cycle combustion system, heat input, whichever is greater, including distillate and residual oil, or the combustion turbine portion of averaged over a 24-month block solid oil-derived fuel (e.g., petroleum any stationary combined cycle steam/ contiguous period commencing April coke) and gases derived from solid oil- electric generating system. Stationary 16, 2015. derived fuels (not meeting the definition means that the combustion turbine is Liquid fuel includes, but is not of natural gas). not self propelled or intended to be limited to, distillate oil and residual oil. Oil-fired electric utility steam propelled while performing its function. Monitoring system malfunction or out generating unit means an electric utility Stationary combustion turbines do not of control period means any sudden, steam generating unit meeting the include turbines located at a research or infrequent, not reasonably preventable definition of ‘‘fossil fuel-fired’’ that is laboratory facility, if research is failure of the monitoring system to not a coal-fired electric utility steam conducted on the turbine itself and the provide valid data. Monitoring system generating unit and that burns oil for turbine is not being used to power other failures that are caused in part by poor more than 10.0 percent of the average applications at the research or maintenance or careless operation are annual heat input during any 3 laboratory facility. not malfunctions. consecutive calendar years or for more Steam generating unit means any Natural gas means a naturally than 15.0 percent of the annual heat furnace, boiler, or other device used for occurring fluid mixture of hydrocarbons input during any one calendar year. combusting fuel for the purpose of (e.g., methane, ethane, or propane) Particulate matter or PM means any producing steam (including fossil-fuel- produced in geological formations finely divided solid material as fired steam generators associated with beneath the Earth’s surface that measured by the test methods specified integrated gasification combined cycle maintains a gaseous state at standard under this subpart, or an alternative gas turbines; nuclear steam generators atmospheric temperature and pressure method. are not included). under ordinary conditions. Natural gas Pulverized coal (PC) boiler means an Stoker means a unit consisting of a contains 20.0 grains or less of total EGU in which pulverized coal is mechanically operated fuel feeding sulfur per 100 standard cubic feet. introduced into an air stream that mechanism, a stationary or moving grate Additionally, natural gas must either be carries the coal to the combustion to support the burning of fuel and admit composed of at least 70 percent methane chamber of the EGU where it is fired in undergrate air to the fuel, an overfire air by volume or have a gross calorific suspension. system to complete combustion, and an value between 950 and 1,100 Btu per Residual oil means crude oil, and all ash discharge system. There are two standard cubic foot. Natural gas does fuel oil numbers 4, 5 and 6, as defined general types of stokers: underfeed and

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overfeed. Overfeed stokers include mass Voluntary consensus standards or branches of the U.S. government, e.g., feed and spreader stokers. VCS mean technical standards (e.g., Department of Defense (DOD) and Subbituminous coal means coal that materials specifications, test methods, Department of Transportation (DOT). is classified as subbituminous A, B, or sampling procedures, business This does not preclude EPA from using C according to ASTM Method D388–05, practices) developed or adopted by one standards developed by groups that are ‘‘Standard Classification of Coals by or more voluntary consensus bodies. not VCS bodies within an EPA rule. Rank’’ (incorporated by reference, see The EPA/OAQPS has by precedent only When this occurs, EPA has done § 63.14). used VCS that are written in English. searches and reviews for VCS equivalent Unit designed for coal > 8,300 Btu/lb Examples of VCS bodies are: American to these non-VCS methods. subcategory means any coal-fired EGU Society of Testing and Materials Wet flue gas desulfurization that is not a coal-fired EGU in the ‘‘unit (ASTM), American Society of technology, or wet FGD, or wet scrubber designed for low rank virgin coal’’ Mechanical Engineers (ASME), means any add-on air pollution control subcategory. International Standards Organization device that is located downstream of the Unit designed for low rank virgin coal steam generating unit that mixes an subcategory means any coal-fired EGU (ISO), Standards Australia (AS), British Standards (BS), Canadian Standards aqueous stream or slurry with the that is designed to burn and that is exhaust gases from an EGU to control burning nonagglomerating virgin coal (CSA), European Standard (EN or CEN) and German Engineering Standards emissions of PM and/or to absorb and having a calorific value (moist, mineral neutralize acid gases, such as SO and matter-free basis) of less than 19,305 kJ/ (VDI). The types of standards that are 2 not considered VCS are standards HCl. kg (8,300 Btu/lb) that is constructed and Work practice standard means any operates at or near the mine that developed by: the U.S. states, e.g., California (CARB) and Texas (TCEQ); design, equipment, work practice, or produces such coal. operational standard, or combination Unit designed to burn solid oil- industry groups, such as American thereof, which is promulgated pursuant derived fuel subcategory means any oil- Petroleum Institute (API), Gas to CAA section 112(h). fired EGU that burns solid oil-derived Processors Association (GPA), and Gas fuel. Research Institute (GRI); and other Tables to Subpart UUUUU of Part 63

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS [As stated in § 63.9991, you must comply with the following applicable emission limits]

Using these requirements, as ap- You must meet the following propriate (e.g., specified sampling If your EGU is in this For the following pollutants . . . emission limits and work practice volume or test run duration) and subcategory . . . standards . . . limitations with the test methods in Table . . .

1. Coal-fired unit not low rank vir- a. Filterable particulate matter 7.0E–3 lb/MWh1 ...... Collect a minimum of 4 dscm per gin coal. (PM). run. OR OR Total non-Hg HAP metals 6.0E–2 lb/GWh ...... Collect a minimum of 4 dscm per run. OR OR individual HAP metals: ...... Collect a minimum of 3 dscm per run. Antimony (Sb) ...... 8.0E–3 lb/GW. Arsenic (As) ...... 3.0E–3 lb/GWh. Beryllium (Be) ...... 6.0E–4 lb/GWh. Cadmium (Cd) ...... 4.0E–4 lb/GWh. Chromium (Cr) ...... 7.0E–3 lb/GWh. Cobalt (Co) ...... 2.0E–3 lb/GWh. Lead (Pb) ...... 2.0E–3 lb/GWh. Manganese (Mn) ...... 4.0E–3 lb/GWh. Nickel (Ni) ...... 4.0E–2 lb/GWh. Selenium (Se) ...... 6.0E–3 lb/GWh. b. Hydrogen chloride (HC1) ...... 4.0E–4 lb/MWh ...... For Method 26A, collect a min- imum of 3 dscm per run. For ASTM D6348–03 2 or Method 320, sample for a minimum of 1 hour. OR. 3 Sulfur dioxide (SO2) ...... 4.0E–1 lb/MWh ...... SO2 CEMS. c. Mercury (Hg) ...... 2.0E–4 lb/GWh ...... Hg CEMS or sorbent trap moni- toring system only.

2. Coal-fired units low rank virgin a. Filterable particulate matter 7.0E–3 lb/MWh1 ...... Collect a minimum of 4 dscm per coal. (PM). run. OR OR Total non-Hg HAP metals ...... 6.0E–2 lb/GWh ...... Collect a minimum of 4 dscm per run. OR OR Individual HAP metals: ...... Collect a minimum of 3 dscm per run. Antimony (Sb) ...... 8.0E–3 lb/GWh. Arsenic (As) ...... 3.0E–3 lb/GWh.

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TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued [As stated in § 63.9991, you must comply with the following applicable emission limits]

Using these requirements, as ap- You must meet the following propriate (e.g., specified sampling If your EGU is in this For the following pollutants . . . emission limits and work practice volume or test run duration) and subcategory . . . standards . . . limitations with the test methods in Table . . .

Beryllium (Be) ...... 6.0E–4 lb/GWh. Cadmium (Cd) ...... 4.0E–4 lb/GWh. Chromium (Cr) ...... 7.0E–3 lb/GWh. Cobalt (Co) ...... 2.0E–3 lb/GWh. Lead (Pb) ...... 2.0E–3 lb/GWh. Manganese (Mn) ...... 4.0E–3 lb/GWh. Nickel (Ni) ...... 4.0E–2 lb/GWh. Selenium (Se) ...... 6.0E–3 lb/GWh. b. Hydrogen chloride (HCl) ...... 4.0E–4 lb/MWh ...... For Method 26A, collect a min- imum of 3 dscm per run. For ASTM D6348–03 2 or Method 320, sample for a minimum of 1 hour. OR 3 Sulfur dioxide (SO2) ...... 4.0E–1 lb/MWh ...... SO2 CEMS. c. Mercury (Hg) ...... 4.0E–2 lb/GWh ...... Hg CEMS or sorbent trap moni- toring system only.

3. IGCC unit...... a. Filterable particulate matter 7.0E–2 lb/MWh 4 ...... Collect a minimum of 1 dscm per (PM). 9.0E–2 lb/MWh 5 run. OR OR Total non-Hg HAP metals ...... 4.0E–1 lb/GWh ...... Collect a minimum of 1 dscm per run. OR OR Individual HAP metals: ...... Collect a minimum of 2 dscm per run. Antimony (Sb) ...... 2.0E–2 lb/GWh. Arsenic (As) ...... 2.0E–2 lb/GWh. Beryllium (Be) ...... 1.0E–3 lb/GWh. Cadmium (Cd) ...... 2.0E–3 lb/GWh. Chromium (Cr) ...... 4.0E–2 lb/GWh. Cobalt (Co) ...... 4.0E–3 lb/GWh. Lead (Pb) ...... 9.0E–3 lb/GWh. Manganese (Mn) ...... 2.0E–2 lb/GWh. Nickel (Ni) ...... 7.0E–2 lb/GWh. Selenium (Se) ...... 3.0E–1 lb/GWh. b. Hydrogen chloride (HCl) ...... 2.0E–3 lb/MWh ...... For Method 26A, collect a min- imum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 2 or Method 320, sample for a minimum of 1 hour. OR 3 2 Sulfur dioxide (SO2) 4.0E–1 lb/MWh ...... SO CEMS. c. Mercury (Hg) ...... 3.0E–3 lb/GWh ...... Hg CEMS or sorbent trap moni- toring system only.

4. Liquid oil-fired unit—continental a. Filterable particulate matter 7.0E–2 lb/MWh1 ...... Collect a minimum of 1 dscm per (excluding limited-use liquid oil- (PM). run. fired subcategory units). OR OR Total HAP metals ...... 2.0E–4 lb/MWh ...... Collect a minimum of 2 dscm per run. OR OR Individual HAP metals: ...... Collect a minimum of 2 dscm per run. Antimony (Sb) ...... 1.0E–2 lb/GWh. Arsenic (As) ...... 3.0E–3 lb/GWh. Beryllium (Be) ...... 5.0E–4 lb/GWh. Cadmium (Cd) ...... 2.0E–4 lb/GWh. Chromium (Cr) ...... 2.0E–2 lb/GWh. Cobalt (Co) ...... 3.0E–2 lb/GWh. Lead (Pb) ...... 8.0E–3 lb/GWh. Manganese (Mn) ...... 2.0E–2 lb/GWh. Nickel (Ni) ...... 9.0E–2 lb/GWh. Selenium (Se) ...... 2.0E–2 lb/GWh.

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TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued [As stated in § 63.9991, you must comply with the following applicable emission limits]

Using these requirements, as ap- You must meet the following propriate (e.g., specified sampling If your EGU is in this For the following pollutants . . . emission limits and work practice volume or test run duration) and subcategory . . . standards . . . limitations with the test methods in Table . . .

Mercury (Hg) 1.0E–4 lb/GWh ...... For Method 30B sample volume determination (Section 8.2.4), the estimated Hg concentration should nominally be <1⁄2 the standard. b. Hydrogen chloride (HCl) 4.0E–4 lb/MWh ...... For Method 26A, collect a min- imum of 3 dscm per run. For ASTM D6348–03 2 or Method 320, sample for a minimum of 1 hour. c. Hydrogen fluoride (HF) 4.0E–4 lb/MWh ...... For Method 26A, collect a min- imum of 3 dscm per run. For ASTM D6348–03 2 or Method 320, sample for a minimum of 1 hour.

5. Liquid oil-fired unit—non-conti- a. Filterable particulate matter 2.0E–1 lb/MWh1 ...... Collect a minimum of 1 dscm per nental (excluding limited-use liq- (PM). run. uid oil-fired subcategory units). OR OR Total HAP metals 7.0E–3 lb/MWh ...... Collect a minimum of 1 dscm per run. OR OR Individual HAP metals: ...... Collect a minimum of 3 dscm per run. Antimony (Sb) ...... 8.0E–3 lb/GWh. Arsenic (As) ...... 6.0E–2 lb/GWh. Beryllium (Be) ...... 2.0E–3 lb/GWh. Cadmium (Cd) ...... 2.0E–3 lb/GWh. Chromium (Cr) ...... 2.0E–2 lb/GWh. Cobalt (Co) ...... 3.0E–1 lb/GWh. Lead (Pb) ...... 3.0E–2 lb/GWh. Manganese (Mn) ...... 1.0E–1 lb/GWh. Nickel (Ni) ...... 4.1E–0 lb/GWh. Selenium (Se) ...... 2.0E–2 lb/GWh. Mercury (Hg) ...... 4.0E–4 lb/GWh ...... For Method 30B sample volume determination (Section 8.2.4), the estimated Hg concentration should nominally be < 1⁄2 the standard. b. Hydrogen chloride (HCl) 2.0E–3 lb/MWh ...... For Method 26A, collect a min- imum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–032 or Method 320, sample for a minimum of 1 hour c. Hydrogen fluoride (HF) 5.0E–4 lb/MWh ...... For Method 26A, collect a min- imum of 3 dscm per run. For ASTM D6348–03 2 or Method 320, sample for a minimum of 1 hour.

6. Solid oil-derived fuel-fired unit ... a. Filterable particulate matter 2.0E–2 lb/MWh1 ...... Collect a minimum of 1 dscm per (PM). run. OR OR Total non-Hg HAP metals 6.0E–1 lb/GWh ...... Collect a minimum of 1 dscm per run. OR OR Individual HAP metals: ...... Collect a minimum of 3 dscm per run. Antimony (Sb) ...... 8.0E–3 lb/GWh. Arsenic (As) ...... 3.0E–3 lb/GWh. Beryllium (Be) ...... 6.0E–4 lb/GWh. Cadmium (Cd) ...... 7.0E–4 lb/GWh. Chromium (Cr) ...... 6.0E–3 lb/GWh. Cobalt (Co) ...... 2.0E–3 lb/GWh.

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TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued [As stated in § 63.9991, you must comply with the following applicable emission limits]

Using these requirements, as ap- You must meet the following propriate (e.g., specified sampling If your EGU is in this For the following pollutants . . . emission limits and work practice volume or test run duration) and subcategory . . . standards . . . limitations with the test methods in Table . . .

Lead (Pb) ...... 2.0E–2 lb/GWh. Manganese (Mn) ...... 7.0E–3 lb/GWh. Nickel (Ni) ...... 4.0E–2 lb/GWh. Selenium (Se) ...... 6.0E–3 lb/GWh. b. Hydrogen chloride (HCl) ...... 4.0E–4 lb/MWh ...... For Method 26A, collect a min- imum of 3 dscm per run. For ASTM D6348–03 2 or Method 320, sample for a minimum of 1 hour. OR

3 Sulfur dioxide (SO2) ...... 4.0E–1 lb/MWh ...... SO2 CEMS. c. Mercury (Hg) ...... 2.0E–3 lb/GWh ...... Hg CEMS or Sorbent trap moni- toring system only. 1 Gross electric output. 2 Incorporated by reference, see § 63.14. 3 You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS installed. 4 Duct burners on syngas; gross electric output. 5 Duct burners on natural gas; gross electric output

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS [As stated in § 63.9991, you must comply with the following applicable emission limits] 1

Using these requirements, as ap- You must meet the following propriate (e.g., specified sampling If your EGU is in this subcategory For the following pollutants emission limits and work practice volume or test run duration) and standards limitations with the test methods in Table 5

1. Coal-fired unit not low rank vir- a. Filterable particulate matter 3.0E–2 lb/MMBtu or 3.0E–1 lb/ Collect a minimum of 1 dscm per gin coal. (PM). MWh 2. run. OR OR Total non-Hg HAP metals...... 5.0E–5 lb/MMBtu or 5.0E–1 lb/ Collect a minimum of 1 dscm per GWh. run. OR OR Individual HAP metals Antimony (Sb) ...... 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. Arsenic (As) ...... 1.1E0 lb/TBtu or 2.0E–2 lb/GWh. Beryllium (Be) ...... 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh. Cadmium (Cd) ...... 3.0E–1 lb/TBtu or 3.0E–3 lb/GWh. Chromium (Cr) ...... 2.8E0 lb/TBtu or 3.0E–2 lb/GWh. Cobalt (Co) ...... 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. Lead (Pb) ...... 1.2E0 lb/TBtu or 2.0E–2 lb/GWh. Manganese (Mn) ...... 4.0E0 lb/TBtu or 5.0E–2 lb/GWh. Nickel (Ni) ...... 3.5E0 lb/TBtu or 4.0E–2 lb/GWh. Selenium (Se) ...... 5.0E0 lb/TBtu or 6.0E–2 lb/GWh. b. Hydrogen chloride (HCl)...... 2.0E–3 lb/MMBtu or 2.0E–2 lb/ For Method 26A, collect a min- MWh. imum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. OR 4 Sulfur dioxide (SO2) ...... 2.0E–1 lb/MMBtu or 1.5E0 lb/ SO2 CEMS. MWh. c. Mercury (Hg) ...... 1.2E0 lb/TBtu or 1.3E–2 lb/GWh .. LEE Testing for 30 days with 10 days maximum per Method 30B run or Hg CEMS or sorbent trap monitoring system only.

2. Coal-fired unit low rank virgin a. Filterable particulate matter 3.0E–2 lb/MMBtu or 3.0E–1 lb/ Collect a minimum of 1 dscm per coal. (PM). MWh2. run. OR OR Total non-Hg HAP metals...... 5.0E–5 lb/MMBtu or 5.0E–1 lb/ Collect a minimum of 1 dscm per GWh. run. OR OR

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TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued [As stated in § 63.9991, you must comply with the following applicable emission limits] 1

Using these requirements, as ap- You must meet the following propriate (e.g., specified sampling If your EGU is in this subcategory For the following pollutants emission limits and work practice volume or test run duration) and standards limitations with the test methods in Table 5

Individual HAP metals: ...... Collect a minimum of 3 dscm per run. Antimony (Sb) ...... 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. Arsenic (As) ...... 1.1E0 lb/TBtu or 2.0E–2 lb/GWh. Beryllium (Be) ...... 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh. Cadmium (Cd) ...... 3.0E–1 lb/TBtu or 3.0E–3 lb/GWh. Chromium (Cr) ...... 2.8E0 lb/TBtu or 3.0E–2 lb/GWh. Cobalt (Co) ...... 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. Lead (Pb) ...... 1.2E0 lb/TBtu or 2.0E–2 lb/GWh. Manganese (Mn) ...... 4.0E0 lb/TBtu or 5.0E–2 lb/GWh. Nickel (Ni) ...... 3.5E0 lb/TBtu or 4.0E–2 lb/GWh. Selenium (Se) ...... 5.0E0 lb/TBtu or 6.0E–2 lb/GWh. b. Hydrogen chloride (HCl)...... 2.0E–3 lb/MMBtu or 2.0E–2 lb/ For Method 26A, collect a min- MWh. imum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. OR 4 Sulfur dioxide (SO2) ...... 2.0E–1 lb/MMBtu or 1.5E0 lb/ SO2 CEMS. MWh. c. Mercury (Hg) ...... 4.0E0 lb/TBtu or 4.0E–2 lb/GWh .. LEE Testing for 30 days with 10 days maximum per Method 30B run or Hg CEMS or sorbent trap monitoring system only.

3. IGCC unit...... a. Filterable particulate matter 4.0E–2 lb/MMBtu or 4.0E–1 lb/ Collect a minimum of 1 dscm per (PM). MWh2. run. OR OR Total non-Hg HAP metals...... 6.0E–5 lb/MMBtu or 5.0E–1 lb/ Collect a minimum of 1 dscm per GWh. run. OR OR Individual HAP metals: ...... Collect a minimum of 2 dscm per run. Antimony (Sb) ...... 1.4E0 lb/TBtu or 2.0E–2 lb/GWh. Arsenic (As) ...... 1.5E0 lb/TBtu or 2.0E–2 lb/GWh. Beryllium (Be) ...... 1.0E–1 lb/TBtu or 1.0E–3 lb/GWh. Cadmium (Cd) ...... 1.5E–1 lb/TBtu or 2.0E–3 lb/GWh. Chromium (Cr) ...... 2.9E0 lb/TBtu or 3.0E–2 lb/GWh. Cobalt (Co) ...... 1.2E0 lb/TBtu or 2.0E–2 lb/GWh. Lead (Pb)...... 1.9E+2 lb/MMBtu or 1.8E0 lb/ MWh. Manganese (Mn) ...... 2.5E0 lb/TBtu or 3.0E–2 lb/GWh. Nickel (Ni) ...... 6.5E0 lb/TBtu or 7.0E–2 lb/GWh. Selenium (Se) ...... 2.2E+1 lb/TBtu or 3.0E–1 lb/GWh. b. Hydrogen chloride (HCl)...... 5.0E–4 lb/MMBtu or 5.0E–3 lb/ For Method 26A, collect a min- MWh. imum of 1 dscm per run; for Method 26, collect a min- imum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. c. Mercury (Hg) ...... 2.5E0 lb/TBtu or 3.0E–2 lb/GWh .. LEE Testing for 30 days with 10 days maximum per Method 30B run or Hg CEMS or sorbent trap monitoring system only.

4. Liquid oil-fired unit—continental a. Filterable particulate matter 3.0E–2 lb/MMBtu or 3.0E–1 lb/ Collect a minimum of 1 dscm per (excluding limited-use liquid oil- (PM). MWh2. run. fired subcategory units). OR OR Total HAP metals...... 8.0E–4 lb/MMBtu or 8.0E–3 lb/ Collect a minimum of 1 dscm per MWh. run. OR OR Individual HAP metals ...... Collect a minimum of 1 dscm per run.

VerDate Mar<15>2010 22:15 Feb 15, 2012 Jkt 226001 PO 00000 Frm 00189 Fmt 4701 Sfmt 4700 E:\FR\FM\16FER2.SGM 16FER2 srobinson on DSK4SPTVN1PROD with RULES2 9492 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued [As stated in § 63.9991, you must comply with the following applicable emission limits] 1

Using these requirements, as ap- You must meet the following propriate (e.g., specified sampling If your EGU is in this subcategory For the following pollutants emission limits and work practice volume or test run duration) and standards limitations with the test methods in Table 5

Antimony (Sb) ...... 1.3E+1 lb/TBtu or 2.0E–1 lb/GWh. Arsenic (As) ...... 2.8E0 lb/TBtu or 3.0E–2 lb/GWh. Beryllium (Be) ...... 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh. Cadmium (Cd) ...... 3.0E–1 lb/TBtu or 2.0E–3 lb/GWh. Chromium (Cr) ...... 5.5E0 lb/TBtu or 6.0E–2 lb/GWh. Cobalt (Co) ...... 2.1E+1 lb/TBtu or 3.0E–1 lb/GWh. Lead (Pb) ...... 8.1E0 lb/TBtu or 8.0E–2 lb/GWh. Manganese (Mn) ...... 2.2E+1 lb/TBtu or 3.0E–1 lb/GWh. Nickel (Ni) ...... 1.1E+2 lb/TBtu or 1.1E0 lb/GWh. Selenium (Se) ...... 3.3E0 lb/TBtu or 4.0E–2 lb/GWh. Mercury (Hg) ...... 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh For Method 30B sample volume determination (Section 8.2.4), the estimated Hg concentration should nominally be < 1⁄2 the standard. b. Hydrogen chloride (HCl)...... 2.0E–3 lb/MMBtu or 1.0E–2 lb/ For Method 26A, collect a min- MWh. imum of 1 dscm per Run; for Method 26, collect a min- imum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. c. Hydrogen fluoride (HF) ...... 4.0E–4 lb/MMBtu or 4.0E–3 lb/ For Method 26A, collect a min- MWh. imum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour.

5. Liquid oil-fired unit—non-conti- a. Filterable particulate matter 3.0E–2 lb/MMBtu or 3.0E–1 lb/ Collect a minimum of 1 dscm per nental (excluding limited-use liq- (PM). MWh2. run. uid oil-fired subcategory units). OR OR Total HAP metals...... 6.0E–4 lb/MMBtu or 7.0E–3 lb/ Collect a minimum of 1 dscm per MWh. run. OR OR Individual HAP metals ...... Collect a minimum of 2 dscm per run. Antimony (Sb) ...... 2.2E0 lb/TBtu or 2.0E–2 lb/GWh. Arsenic (As) ...... 4.3E0 lb/TBtu or 8.0E–2 lb/GWh. Beryllium (Be) ...... 6.0E–1 lb/TBtu or 3.0E–3 lb/GWh. Cadmium (Cd) ...... 3.0E–1 lb/TBtu or 3.0E–3 lb/GWh. Chromium (Cr) ...... 3.1E+1 lb/TBtu or 3.0E–1 lb/GWh. Cobalt (Co) ...... 1.1E+2 lb/TBtu or 1.4E0 lb/GWh. Lead (Pb) ...... 4.9E0 lb/TBtu or 8.0E–2 lb/GWh. Manganese (Mn) ...... 2.0E+1 lb/TBtu or 3.0E–1 lb/GWh. Nickel (Ni) ...... 4.7E+2 lb/TBtu or 4.1E0 lb/GWh. Selenium (Se) ...... 9.8E0 lb/TBtu or 2.0E–1 lb/GWh. Mercury (Hg) ...... 4.0E–2 lb/TBtu or 4.0E–4 lb/GWh For Method 30B sample volume determination (Section 8.2.4), the estimated Hg concentration should nominally be < 1⁄2 the standard. Hydrogen chloride (HCl) ...... 2.0E–4 lb/MMBtu or 2.0E–3 lb/ For Method 26A, collect a min- MWh. imum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 2 hours. c. Hydrogen fluoride (HF) ...... 6.0E–5 lb/MMBtu or 5.0E–4 lb/ For Method 26A, collect a min- MWh. imum of 3 dscm per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 2 hours.

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TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued [As stated in § 63.9991, you must comply with the following applicable emission limits] 1

Using these requirements, as ap- You must meet the following propriate (e.g., specified sampling If your EGU is in this subcategory For the following pollutants emission limits and work practice volume or test run duration) and standards limitations with the test methods in Table 5

6. Solid oil-derived fuel-fired unit .. a. Filterable particulate matter 8.0E–3 lb/MMBtu or 9.0E–2 lb/ Collect a minimum of 1 dscm per (PM). MWh2. run. OR OR Total non-Hg HAP metals...... 4.0E–5 lb/MMBtu or 6.0E–1 lb/ Collect a minimum of 1 dscm per GWh. run. OR OR Individual HAP metals ...... Collect a minimum of 3 dscm per run. Antimony (Sb) ...... 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. Arsenic (As) ...... 3.0E–1 lb/TBtu or 5.0E–3 lb/GWh. Beryllium (Be) ...... 6.0E–2 lb/TBtu or 6.0E–4 lb/GWh. Cadmium (Cd) ...... 3.0E–1 lb/TBtu or 4.0E–3 lb/GWh. Chromium (Cr) ...... 8.0E–1 lb/TBtu or 2.0E–2 lb/GWh. Cobalt (Co) ...... 1.1E0 lb/TBtu or 2.0E–2 lb/GWh. Lead (Pb) ...... 8.0E–1 lb/TBtu or 2.0E–2 lb/GWh. Manganese (Mn) ...... 2.3E0 lb/TBtu or 4.0E–2 lb/GWh. Nickel (Ni) ...... 9.0E0 lb/TBtu or 2.0E–1 lb/GWh. Selenium (Se) ...... 1.2E0 lb/TBtu 2.0E–2 lb/GWh. b. Hydrogen chloride (HCl)...... 5.0E–3 lb/MMBtu or 8.0E–2 lb/ For Method 26A, collect a min- MWh. imum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. OR 4 Sulfur dioxide (SO2) ...... 3.0E–1 lb/MMBtu or 2.0E0 lb/ SO2 CEMS. MWh. c. Mercury (Hg) ...... 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh LEE Testing for 30 days with 10 days maximum per Method 30B run or Hg CEMS or Sorbent trap monitoring system only. 1 For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required minimum sampling volume must be increased nominally by a factor of two. 2 Gross electric output. 3 Incorporated by reference, see § 63.14. 4 You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS installed.

TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS [As stated in §§ 63.9991, you must comply with the following applicable work practice standards]

If your EGU is . . . You must meet the following . . .

1. An existing EGU ...... Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar months, or each 48 calendar months if neural network combustion optimization software is employed, as specified in § 63.10021(e).

2. A new or reconstructed EGU ...... Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar months, or each 48 calendar months if neural network combustion optimization software is employed, as specified in § 63.10021(e).

3. A coal-fired, liquid oil-fired, or solid oil-de- You must operate all CMS during startup. Startup means either the first-ever firing of fuel in a rived fuel-fired EGU during startup. boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam from the boiler is used to gen- erate electricity for sale over the grid or for any other purpose (including on site use). For startup of a unit, you must use clean fuels, either natural gas or distillate oil or a combina- tion of clean fuels for ignition. Once you convert to firing coal, residual oil, or solid oil-de- rived fuel, you must engage all of the applicable control technologies except dry scrubber and SCR. You must start your dry scrubber and SCR systems, if present, appropriately to comply with relevant standards applicable during normal operation. You must comply with all applicable emissions limits at all times except for periods that meet the definitions of startup and shutdown in this subpart. You must keep records during periods of startup. You must provide reports concerning activities and periods of startup, as specified in § 63.10011(g) and § 63.10021(h) and (i).

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TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS—Continued [As stated in §§ 63.9991, you must comply with the following applicable work practice standards]

If your EGU is . . . You must meet the following . . .

4. A coal-fired, liquid oil-fired, or solid oil-de- You must operate all CMS during shutdown. Shutdown means the cessation of operation of a rived fuel-fired EGU during shutdown. boiler for any purpose. Shutdown begins either when none of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on-site use) or at the point of no fuel being fired in the boiler. Shutdown ends when there is both no electricity being generated and no fuel being fired in the boiler. During shutdown, you must operate all applicable control technologies while firing coal, residual oil, or solid oil-derived fuel. You must comply with all applicable emissions limits at all times except for periods that meet the definitions of startup and shutdown in this subpart. You must keep records during periods of startup. You must provide reports concerning activities and periods of startup, as specified in § 63.10011(g) and § 63.10021(h) and (i).

TABLE 4 TO SUBPART UUUUU OF PART 63—OPERATING LIMITS FOR EGUS [As stated in § 63.9991, you must comply with the applicable operating limits]

If you demonstrate compliance using . . . You must meet these operating limits . . .

1. PM CPMS ...... Maintain the 30-boiler operating day rolling average PM CPMS output at or below the highest 1-hour average measured during the most recent performance test demonstrating compli- ance with the filterable PM, total non-mercury HAP metals (total HAP metals, for liquid oil- fired units), or individual non-mercury HAP metals (individual HAP metals including Hg, for liquid oil-fired units) emissions limitation(s).

TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS [As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected sources 1]

To conduct a perform- You must perform the following activities, as ance test for the fol- Using . . . applicable to your input- or output-based Using 2 ... lowing pollutant . . . emission limit . . .

1. Filterable Particulate Emissions Testing ...... a. Select sampling ports location and the Method 1 at Appendix A–1 to part 60 of this matter (PM). number of traverse points. chapter. b. Determine velocity and volumetric flow-rate Method 2, 2A, 2C, 2F, 2G or 2H at Appendix of the stack gas. A–1 or A–2 to part 60 of this chapter. c. Determine oxygen and carbon dioxide con- Method 3A or 3B at Appendix A–2 to part 60 centrations of the stack gas. of this chapter, or ANSI/ASME PTC 19.10– 1981.3 d. Measure the moisture content of the stack Method 4 at Appendix A–3 to part 60 of this gas. chapter. e. Measure the filterable PM concentration .... Method 5 at Appendix A–3 to part 60 of this chapter. For positive pressure fabric filters, Method 5D at Appendix A–3 to part 60 of this chapter for filterable PM emissions. Note that the Method 5 front half temperature shall be 160 ° ± 14 °C (320 ° ± 25 °F). f. Convert emissions concentration to lb/ Method 19 F-factor methodology at Appendix MMBtu or lb/MWh emissions rates. A–7 to part 60 of this chapter, or calculate using mass emissions rate and electrical output data (see § 63.10007(e)). OR OR PM CEMS a. Install, certify, operate, and maintain the Performance Specification 11 at Appendix B PM CEMS. to part 60 of this chapter and Procedure 2 at Appendix F to Part 60 of this chapter. b. Install, certify, operate, and maintain the Part 75 of this chapter and §§ 63.10010(a), diluent gas, flow rate, and/or moisture mon- (b), (c), and (d). itoring systems. c. Convert hourly emissions concentrations to Method 19 F-factor methodology at Appendix 30 boiler operating day rolling average lb/ A–7 to part 60 of this chapter, or calculate MMBtu or lb/MWh emissions rates. using mass emissions rate and electrical output data (see § 63.10007(e)).

2. Total or individual Emissions Testing ...... a. Select sampling ports location and the Method 1 at Appendix A–1 to part 60 of this non-Hg HAP metals. number of traverse points. chapter. b. Determine velocity and volumetric flow-rate Method 2, 2A, 2C, 2F, 2G or 2H at Appendix of the stack gas. A–1 or A–2 to part 60 of this chapter.

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TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued [As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected sources 1]

To conduct a perform- You must perform the following activities, as ance test for the fol- Using . . . applicable to your input- or output-based Using 2 ... lowing pollutant . . . emission limit . . .

c. Determine oxygen and carbon dioxide con- Method 3A or 3B at Appendix A–2 to part 60 centrations of the stack gas. of this chapter, or ANSI/ASME PTC 19.10– 1981.3 d. Measure the moisture content of the stack Method 4 at Appendix A–3 to part 60 of this gas. chapter. e. Measure the HAP metals emissions con- Method 29 at Appendix A–8 to part 60 of this centrations and determine each individual chapter. For liquid oil-fired units, Hg is in- HAP metals emissions concentration, as cluded in HAP metals and you may use well as the total filterable HAP metals Method 29, Method 30B at Appendix A–8 emissions concentration and total HAP to part 60 of this chapter; for Method 29, metals emissions concentration. you must report the front half and back half results separately. f. Convert emissions concentrations (indi- Method 19 F-factor methodology at Appendix vidual HAP metals, total filterable HAP A–7 to part 60 of this chapter, or calculate metals, and total HAP metals) to lb/MMBtu using mass emissions rate and electrical or lb/MWh emissions rates. output data (see § 63.10007(e)).

3. Hydrogen chloride Emissions Testing ...... a. Select sampling ports location and the Method 1 at Appendix A–1 to part 60 of this (HCl) and hydrogen number of traverse points. chapter. fluoride (HF). b. Determine velocity and volumetric flow-rate Method 2, 2A, 2C, 2F, 2G or 2H at Appendix of the stack gas. A–1 or A–2 to part 60 of this chapter. c. Determine oxygen and carbon dioxide con- Method 3A or 3B at Appendix A–2 to part 60 centrations of the stack gas. of this chapter, or ANSI/ASME PTC 19.10– 1981.3 d. Measure the moisture content of the stack Method 4 at Appendix A–3 to part 60 of this gas. chapter. e. Measure the HCl and HF emissions con- Method 26 or Method 26A at Appendix A–8 centrations. to part 60 of this chapter or Method 320 at Appendix A to part 63 of this chapter or ASTM 6348–03 3 with (1) additional quality assurance measures in footnote 4 and (2) spiking levels nominally no greater than two times the level corresponding to the applicable emission limit. Method 26A must be used if there are entrained water drop- lets in the exhaust stream. f. Convert emissions concentration to lb/ Method 19 F-factor methodology at Appendix MMBtu or lb/MWh emissions rates. A–7 to part 60 of this chapter, or calculate using mass emissions rate and electrical output data (see § 63.10007(e)). OR OR HCl and/or HF CEMS a. Install, certify, operate, and maintain the Appendix B of this subpart. HCl or HF CEMS. b. Install, certify, operate, and maintain the Part 75 of this chapter and §§ 63.10010(a), diluent gas, flow rate, and/or moisture mon- (b), (c), and (d). itoring systems. c. Convert hourly emissions concentrations to Method 19 F-factor methodology at Appendix 30 boiler operating day rolling average lb/ A–7 to part 60 of this chapter, or calculate MMBtu or lb/MWh emissions rates. using mass emissions rate and electrical output data (see § 63.10007(e)).

4. Mercury (Hg) ...... Emissions Testing ...... a. Select sampling ports location and the Method 1 at Appendix A–1 to part 60 of this number of traverse points. chapter or Method 30B at Appendix A–8 for Method 30B point selection. b. Determine velocity and volumetric flow-rate Method 2, 2A, 2C, 2F, 2G or 2H at Appendix of the stack gas. A–1 or A–2 to part 60 of this chapter. c. Determine oxygen and carbon dioxide con- Method 3A or 3B at Appendix A–1 to part 60 centrations of the stack gas. of this chapter, or ANSI/ASME PTC 19.10– 1981.3 d. Measure the moisture content of the stack Method 4 at Appendix A–3 to part 60 of this gas. chapter. e. Measure the Hg emission concentration .... Method 30B at Appendix A–8 to part 60 of this chapter, ASTM D6784 3, or Method 29 at Appendix A–8 to part 60 of this chapter; for Method 29, you must report the front half and back half results separately.

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TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued [As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected sources 1]

To conduct a perform- You must perform the following activities, as ance test for the fol- Using . . . applicable to your input- or output-based Using 2 ... lowing pollutant . . . emission limit . . .

f. Convert emissions concentration to lb/TBtu Method 19 F-factor methodology at Appendix or lb/GWh emission rates. A–7 to part 60 of this chapter, or calculate using mass emissions rate and electrical output data (see § 63.10007(e)). OR OR Hg CEMS ...... Sections 3.2.1 and 5.1 of Appendix A of this a. Install, certify, operate, and maintain the subpart. CEMS. b. Install, certify, operate, and maintain the Part 75 of this chapter and §§ 63.10010(a), diluent gas, flow rate, and/or moisture mon- (b), (c), and (d). itoring systems. c. Convert hourly emissions concentrations to Section 6 of Appendix A to this subpart. 30 boiler operating day rolling average lb/ TBtu or lb/GWh emissions rates. OR OR Sorbent trap moni- a. Install, certify, operate, and maintain the Sections 3.2.2 and 5.2 of Appendix A to this toring system. sorbent trap monitoring system. subpart. b. Install, operate, and maintain the diluent Part 75 of this chapter and §§ 63.10010(a), gas, flow rate, and/or moisture monitoring (b), (c), and (d). systems. c. Convert emissions concentrations to 30 Section 6 of Appendix A to this subpart. boiler operating day rolling average lb/TBtu or lb/GWh emissions rates. OR OR LEE testing...... a. Select sampling ports location and the Single point located at the 10% centroidal number of traverse points. area of the duct at a port location per Method 1 at Appendix A–1 to part 60 of this chapter or Method 30B at Appendix A– 8 for Method 30B point selection. b. Determine velocity and volumetric flow-rate Method 2, 2A, 2C, 2F, 2G, or 2H at Appendix of the stack gas. A–1 or A–2 to part 60 of this chapter or flow monitoring system certified per Appen- dix A of this subpart. c. Determine oxygen and carbon dioxide con- Method 3A or 3B at Appendix A–1 to part 60 centrations of the stack gas. of this chapter, or ANSI/ASME PTC 19.10– 1981,3 or diluent gas monitoring systems certified according to Part 75 of this chap- ter. d. Measure the moisture content of the stack Method 4 at Appendix A–3 to part 60 of this gas. chapter, or moisture monitoring systems certified according to part 75 of this chap- ter. e. Measure the Hg emission concentration .... Method 30B at Appendix A–8 to part 60 of this chapter; perform a 30 operating day test, with a maximum of 10 operating days per run (i.e., per pair of sorbent traps) or sorbent trap monitoring system or Hg CEMS certified per Appendix A of this sub- part. f. Convert emissions concentrations from the Method 19 F-factor methodology at Appendix LEE test to lb/TBtu or lb/GWh emissions A–7 to part 60 of this chapter, or calculate rates. using mass emissions rate and electrical output data (see § 63.10007(e)). g. Convert average lb/TBtu or lb/GWh Hg Potential maximum annual heat input in TBtu emission rate to lb/year, if you are attempt- or potential maximum electricity generated ing to meet the 22.0 lb/year threshold. in GWh.

5. Sulfur dioxide (SO2) SO2 CEMS ...... a. Install, certify, operate, and maintain the Part 75 of this chapter and §§ 63.10010(a) CEMS. and (f). b. Install, operate, and maintain the diluent Part 75 of this chapter and §§ 63.10010(a), gas, flow rate, and/or moisture monitoring (b), (c), and (d). systems. c. Convert hourly emissions concentrations to Method 19 F-factor methodology at Appendix 30 boiler operating day rolling average lb/ A–7 to part 60 of this chapter, or calculate MMBtu or lb/MWh emissions rates. using mass emissions rate and electrical output data (see § 63.10007(e)). 1 Regarding emissions data collected during periods of startup or shutdown, see §§ 63.10020(b) and (c) and § 63.10021(h).

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2 See Tables 1 and 2 to this subpart for required sample volumes and/or sampling run times. 3 Incorporated by reference, see § 63.14. 4 When using ASTM D6348–03, the following conditions must be met: (1) The test plan preparation and implementation in the Annexes to ASTM D6348–03, Sections A1 through A8 are mandatory; (2) For ASTM D6348–03 Annex A5 (Analyte Spiking Technique), the percent (%) R must be determined for each target analyte (see Equation A5.5); (3) For the ASTM D6348–03 test data to be acceptable for a target analyte, %R must be 70% ≥ R ≤ 130%; and (4) The %R value for each compound must be reported in the test report and all field measurements corrected with the calculated %R value for that compound using the following equation:

TABLE 6 TO SUBPART UUUUU OF PART 63—ESTABLISHING PM CPMS OPERATING LIMITS [As stated in § 63.10007, you must comply with the following requirements for establishing operating limits]

And you choose to establish If you have an applicable PM CPMS operating limits, And . . . Using . . . According to the following emission limit for . . . you must . . . procedures . . .

Particulate matter (PM), Install, certify, maintain, and Establish a site-specific Data from the PM CPMS 1. Collect PM CPMS out- total non-mercury HAP operate a PM CPMS for operating limit in units and the PM or HAP put data during the en- metals, individual non- monitoring emissions dis- of PM CPMS output metals performance tire period of the per- mercury HAP metals, charged to the atmosphere signal (e.g., milliamps, tests. formance tests. total HAP metals, indi- according to mg/acm, or other raw 2. Record the average vidual HAP metals. § 63.10010(g)(1). signal). hourly PM CPMS out- put for each test run in the three run perform- ance test. 3. Determine the highest 1-hour average PM CPMS measured dur- ing the performance test demonstrating compliance with the fil- terable PM or HAP metals emissions limi- tations.

TABLE 7 TO SUBPART UUUUU OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE [As stated in § 63.10021, you must show continuous compliance with the emission limitations for affected sources according to the following]

If you use one of the following to meet applicable emissions limits, op- erating limits, or work practice standards . . . You demonstrate continuous compliance by . . .

1. CEMS to measure filterable PM, SO2, HCl, HF, or Hg emissions, or Calculating the 30-boiler operating day rolling arithmetic average emis- using a sorbent trap monitoring system to measure Hg. sions rate in units of the applicable emissions standard basis at the end of each boiler operating day using all of the quality assured hourly average CEMS or sorbent trap data for the previous 30 boiler operating days, excluding data recorded during periods of startup or shutdown. 2. PM CPMS to measure compliance with a parametric operating limit Calculating the arithmetic 30-boiler operating day rolling average of all of the quality assured hourly average PM CPMS output data (e.g., milliamps, PM concentration, raw data signal) collected for all oper- ating hours for the previous 30 boiler operating days, excluding data recorded during periods of startup or shutdown. 3. Site-specific monitoring for liquid oil-fired units for HCl and HF emis- If applicable, by conducting the monitoring in accordance with an ap- sion limit monitoring. proved site-specific monitoring plan. 4. Quarterly performance testing for coal-fired, solid oil derived fired, or Calculating the results of the testing in units of the applicable emis- liquid oil-fired units to measure compliance with one or more applica- sions standard. ble emissions limit in Table 1 or 2. 5. Conducting periodic performance tune-ups of your EGU(s) ...... Conducting periodic performance tune-ups of your EGU(s), as speci- fied in § 63.10021(e). 6. Work practice standards for coal-fired, liquid oil-fired, or solid oil-de- Operating in accordance with Table 3. rived fuel-fired EGUs during startup. 7. Work practice standards for coal-fired, liquid oil-fired, or solid oil-de- Operating in accordance with Table 3. rived fuel-fired EGUs during shutdown.

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TABLE 8 TO SUBPART UUUUU OF PART 63—REPORTING REQUIREMENTS [As stated in § 63.10031, you must comply with the following requirements for reports]

You must submit a . . . The report must contain . . . You must submit the report . . .

1. Compliance report ...... a. Information required in § 63.10031(c)(1) through (4); and Semiannually according to the b. If there are no deviations from any emission limitation (emission limit and op- requirements in erating limit) that applies to you and there are no deviations from the require- § 63.10031(b). ments for work practice standards in Table 3 to this subpart that apply to you, a statement that there were no deviations from the emission limitations and work practice standards during the reporting period. If there were no periods during which the CMSs, including continuous emissions monitoring system, and operating parameter monitoring systems, were out-of-control as specified in § 63.8(c)(7), a statement that there were no periods during which the CMSs were out-of-control during the reporting period; and c. If you have a deviation from any emission limitation (emission limit and oper- ating limit) or work practice standard during the reporting period, the report must contain the information in § 63.10031(d). If there were periods during which the CMSs, including continuous emissions monitoring systems and continuous parameter monitoring systems, were out-of-control, as specified in § 63.8(c)(7), the report must contain the information in § 63.10031(e).

TABLE 9 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU [As stated in § 63.10040, you must comply with the applicable General Provisions according to the following]

Citation Subject Applies to subpart UUUUU

§ 63.1 ...... Applicability ...... Yes. § 63.2 ...... Definitions ...... Yes. Additional terms defined in § 63.10042. § 63.3 ...... Units and Abbreviations ...... Yes. § 63.4 ...... Prohibited Activities and Circumvention ...... Yes. § 63.5 ...... Preconstruction Review and Notification Re- Yes. quirements. § 63.6(a), (b)(1)–(b)(5), (b)(7), (c), (f)(2)–(3), Compliance with Standards and Maintenance Yes. (g), (h)(2)–(h)(9), (i), (j). Requirements. § 63.6(e)(1)(i) ...... General Duty to minimize emissions ...... No. See § 63.10000(b) for general duty re- quirement. § 63.6(e)(1)(ii) ...... Requirement to correct malfunctions ASAP .... No. § 63.6(e)(3) ...... SSM Plan requirements ...... No. § 63.6(f)(1) ...... SSM exemption ...... No. § 63.6(h)(1) ...... SSM exemption ...... No. § 63.7(a), (b), (c), (d), (e)(2)–(e)(9), (f), (g), and Performance Testing Requirements ...... Yes. (h). § 63.7(e)(1) ...... Performance testing ...... No. See § 63.10007. § 63.8 ...... Monitoring Requirements ...... Yes. 63.8(c)(1)(i) ...... General duty to minimize emissions and CMS No. See § 63.10000(b) for general duty re- operation. quirement. § 63.8(c)(1)(iii) ...... Requirement to develop SSM Plan for CMS ... No. § 63.8(d)(3) ...... Written procedures for CMS ...... Yes, except for last sentence, which refers to an SSM plan. SSM plans are not required. § 63.9 ...... Notification Requirements ...... Yes. § 63.10(a), (b)(1), (c), (d)(1)–(2), (e), and (f) ..... Recordkeeping and Reporting Requirements .. Yes, except for the requirements to submit written reports under § 63.10(e)(3)(v). § 63.10(b)(2)(i) ...... Recordkeeping of occurrence and duration of No. startups and shutdowns. § 63.10(b)(2)(ii) ...... Recordkeeping of malfunctions ...... No. See 63.10001 for recordkeeping of (1) oc- currence and duration and (2) actions taken during malfunction. § 63.10(b)(2)(iii) ...... Maintenance records ...... Yes. § 63.10(b)(2)(iv) ...... Actions taken to minimize emissions during No. SSM. § 63.10(b)(2)(v) ...... Actions taken to minimize emissions during No. SSM. § 63.10(b)(2)(vi) ...... Recordkeeping for CMS malfunctions ...... Yes. § 63.10(b)(2)(vii)–(ix) ...... Other CMS requirements ...... Yes. § 63.10(b)(3), and (d)(3)–(5) ...... No. § 63.10(c)(7) ...... Additional recordkeeping requirements for Yes. CMS—identifying exceedances and excess emissions. § 63.10(c)(8) ...... Additional recordkeeping requirements for Yes. CMS—identifying exceedances and excess emissions. § 63.10(c)(10) ...... Recording nature and cause of malfunctions .. No. See 63.10032(g) and (h) for malfunctions recordkeeping requirements.

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TABLE 9 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU—Continued [As stated in § 63.10040, you must comply with the applicable General Provisions according to the following]

Citation Subject Applies to subpart UUUUU

§ 63.10(c)(11) ...... Recording corrective actions ...... No. See 63.10032(g) and (h) for malfunctions recordkeeping requirements. § 63.10(c)(15) ...... Use of SSM Plan ...... No. § 63.10(d)(5) ...... SSM reports ...... No. See 63.10021(h) and (i) for malfunction reporting requirements. § 63.11 ...... Control Device Requirements ...... No. § 63.12 ...... State Authority and Delegation ...... Yes. § 63.13–63.16 ...... Addresses, Incorporation by Reference, Avail- Yes. ability of Information, Performance Track Provisions. § 63.1(a)(5), (a)(7)–(a)(9), (b)(2), (c)(3)–(4), (d), Reserved ...... No. 63.6(b)(6), (c)(3), (c)(4), (d), (e)(2), (e)(3)(ii), (h)(3), (h)(5)(iv), 63.8(a)(3), 63.9(b)(3), (h)(4), 63.10(c)(2)–(4), (c)(9).

Appendix A to Subpart UUUUU—Hg continuous monitoring systems (CMS). These CEMS. Except as otherwise provided in Monitoring Provisions CMS installation provisions apply to the Hg section 2.2.4.5 of this appendix, a non- CEMS, sorbent trap monitoring systems, and redundant backup monitoring system may 1. General Provisions other continuous monitoring systems that only be used for 720 hours per year at a 1.1 Applicability. These monitoring provide data for the Hg emissions particular unit or stack location. provisions apply to the measurement of total calculations in section 6.2 of this appendix. 2.2.3 Temporary Like-kind Replacement vapor phase mercury (Hg) in emissions from 2.2 Primary and Backup Monitoring Analyzers. When a primary Hg analyzer electric utility steam generating units, using Systems. In the electronic monitoring plan needs repair or maintenance, you may either a mercury continuous emission described in section 7.1.1.2.1 of this temporarily install a like-kind replacement monitoring system (Hg CEMS) or a sorbent appendix, you must designate a primary Hg analyzer, to minimize data loss. Except as trap monitoring system. The Hg CEMS or CEMS or sorbent trap monitoring system. The otherwise provided in section 2.2.4.5 of this sorbent trap monitoring system must be primary system must be used to report hourly appendix, a temporary like-kind replacement capable of measuring the total vapor phase Hg concentration values when the system is analyzer may only be used for 720 hours per mercury in units of the applicable emissions able to provide quality-assured data, i.e., year at a particular unit or stack location. The standard (e.g., lb/TBtu or lb/GWh), regardless when the system is ‘‘in control’’. However, to analyzer must be represented as a component of speciation. increase data availability in the event of a of the primary Hg CEMS, and must be 1.2 Initial Certification and primary monitoring system outage, you may assigned a 3-character component ID number, Recertification Procedures. The owner or install, operate, maintain, and calibrate beginning with the prefix ‘‘LK’’. backup monitoring systems, as follows: operator of an affected unit that uses a Hg 2.2.4 Quality Assurance Requirements for 2.2.1 Redundant Backup Systems. A CEMS or a sorbent trap monitoring system Non-redundant Backup Monitoring Systems redundant backup monitoring system may be together with other necessary monitoring and Temporary Like-kind Replacement either a separate Hg CEMS with its own components to account for Hg emissions in Analyzers. To quality-assure the data from probe, sample interface, and analyzer, or a units of the applicable emissions standard non-redundant backup Hg monitoring shall comply with the initial certification and separate sorbent trap monitoring system. A redundant backup system is one that is systems and temporary like-kind replacement recertification procedures in section 4 of this Hg analyzers, the following provisions apply: appendix. permanently installed at the unit or stack 2.2.4.1 When a certified non-redundant 1.3 Quality Assurance and Quality location, and is kept on ‘‘hot standby’’ in case backup sorbent trap monitoring system is Control Requirements. The owner or operator the primary monitoring system is unable to brought into service, you must follow the of an affected unit that uses a Hg CEMS or provide quality-assured data. A redundant procedures for routine day-to-day operation a sorbent trap monitoring system together backup system must be represented as a with other necessary monitoring components unique monitoring system in the electronic of the system, in accordance with to account for Hg emissions in units of the monitoring plan. Each redundant backup Performance Specification (PS) 12B in applicable emissions standard shall meet the monitoring system must be certified appendix B to part 60 of this chapter. applicable quality assurance requirements in according to the applicable provisions in 2.2.4.2 When a certified non-redundant section 5 of this appendix. section 4 of this appendix and must meet the backup Hg CEMS or a temporary like-kind 1.4 Missing Data Procedures. The owner applicable on-going QA requirements in replacement Hg analyzer is brought into or operator of an affected unit is not required section 5 of this appendix. service, a calibration error test and a linearity to substitute for missing data from Hg CEMS 2.2.2 Non-redundant Backup Monitoring check must be performed and passed. A or sorbent trap monitoring systems. Any Systems. A non-redundant backup single point system integrity check is also process operating hour for which quality- monitoring system is a separate Hg CEMS or required, unless a NIST-traceable source of assured Hg concentration data are not sorbent trap system that has been certified at oxidized Hg was used for the calibration obtained is counted as an hour of monitoring a particular unit or stack location, but is not error test. system downtime. permanently installed at that location. 2.2.4.3 Each non-redundant backup Hg Rather, the system is kept on ‘‘cold standby’’ CEMS or temporary like-kind replacement Hg 2. Monitoring of Hg Emissions and may be reinstalled in the event of a analyzer shall comply with all required daily, 2.1 Monitoring System Installation primary monitoring system outage. A non- weekly, and quarterly quality-assurance test Requirements. Flue gases from the affected redundant backup monitoring system must requirements in section 5 of this appendix, units under this subpart vent to the be represented as a unique monitoring for as long as the system or analyzer remains atmosphere through a variety of exhaust system in the electronic monitoring plan. in service. configurations including single stacks, Non-redundant backup Hg CEMS must 2.2.4.4 For the routine, on-going quality- common stack configurations, and multiple complete the same certification tests as the assurance of a non-redundant backup Hg stack configurations. For each of these primary monitoring system, with one monitoring system, a relative accuracy test configurations, § 63.10010(a) specifies the exception. The 7-day calibration error test is audit (RATA) must be performed and passed appropriate location(s) at which to install not required for a non-redundant backup Hg at least once every 8 calendar quarters at the

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unit or stack location(s) where the system cylinders having known concentrations of measurement of oxidized Hg by a Hg CEMS. will be used. elemental Hg, which have been prepared Oxidized Hg standards are used for this test. 2.2.4.5 To use a non-redundant backup according to the ‘‘EPA Traceability Protocol For a three-level system integrity check, low, Hg monitoring system or a temporary like- for Assay and Certification of Gaseous mid, and high-level calibration gases are kind replacement analyzer for more than 720 Calibration Standards’’; or calibration gases required. For a single-level check, either a having known concentrations of elemental hours per year at a particular unit or stack mid-level gas or a high-level gas may be used. location, a RATA must first be performed and Hg, produced by a generator that meets the 3.1.15 Cycle Time Test means a test passed at that location. performance requirements of the ‘‘EPA Traceability Protocol for Qualification and designed to measure the amount of time it 3. Mercury Emissions Measurement Methods Certification of Elemental Mercury Gas takes for a Hg CEMS, while operating The following definitions, equipment Generators’’ or an interim version of that normally, to respond to a known step change specifications, procedures, and performance protocol. in gas concentration. For this test, a zero gas criteria are applicable to the measurement of 3.1.5 NIST–Traceable Source of Oxidized and a high-level gas are required. The high- vapor-phase Hg emissions from electric Hg means a generator that is capable of level gas may be either an elemental or an utility steam generating units, under providing known concentrations of vapor oxidized Hg standard. relatively low-dust conditions (i.e., sampling phase mercuric chloride (HgCl2), and that 3.1.16 Relative Accuracy Test Audit or in the stack or duct after all pollution control meets the performance requirements of the RATA means a series of nine or more test devices). The analyte measured by these ‘‘EPA Traceability Protocol for Qualification runs, directly comparing readings from a Hg procedures and specifications is total vapor- and Certification of Mercuric Chloride Gas phase Hg in the flue gas, which represents Generators’’ or an interim version of that CEMS or sorbent trap monitoring system to the sum of elemental Hg (Hg0, CAS Number protocol. measurements made with a reference stack 7439–97–6) and oxidized forms of Hg. 3.1.6 Calibration Gas means a NIST- test method. The relative accuracy (RA) of 3.1 Definitions. traceable gas standard containing a known the monitoring system is expressed as the 3.1.1 Mercury Continuous Emission concentration of elemental or oxidized Hg absolute mean difference between the Monitoring System or Hg CEMS means all of that is produced and certified in accordance monitoring system and reference method the equipment used to continuously with an EPA traceability protocol. measurements plus the absolute value of the determine the total vapor phase Hg 3.1.7 Span Value means a conservatively 2.5 percent error confidence coefficient, concentration. The measurement system may high estimate of the Hg concentrations to be divided by the mean value of the reference include the following major subsystems: measured by a CEMS. The span value of a Hg method measurements. sample acquisition, Hg∂2 to Hg0 converter, CEMS should be set to approximately twice 3.1.17 Unit Operating Hour means a sample transport, sample conditioning, flow the concentration corresponding to the control/gas manifold, gas analyzer, and data emission standard, rounded off as clock hour in which a unit combusts any acquisition and handling system (DAHS). Hg appropriate (see section 3.2.1.4.2 of this fuel, either for part of the hour or for the CEMS may be nominally real-time or time- appendix). entire hour. integrated, batch sampling systems that 3.1.8 Zero-Level Gas means calibration 3.1.18 Stack Operating Hour means a sample the gas on an intermittent basis and gas containing a Hg concentration that is clock hour in which gases flow through a concentrate on a collection medium before below the level detectable by the Hg gas particular monitored stack or duct (either for intermittent analysis and reporting. analyzer in use. part of the hour or for the entire hour), while 3.1.2 Sorbent Trap Monitoring System 3.1.9 Low-Level Gas means calibration gas the associated unit(s) are combusting fuel. means the equipment required to monitor Hg with a concentration that is 20 to 30 percent 3.1.19 Operating Day means a calendar emissions continuously by using paired of the span value. day in which a source combusts any fuel. sorbent traps containing iodated charcoal (IC) 3.1.10 Mid-Level Gas means calibration 3.1.20 Quality Assurance (QA) Operating or other suitable sorbent medium. The gas with a concentration that is 50 to 60 monitoring system consists of a probe, paired percent of the span value. Quarter means a calendar quarter in which sorbent traps, an umbilical line, moisture 3.1.11 High-Level Gas means calibration there are at least 168 unit or stack operating removal components, an airtight sample gas with a concentration that is 80 to 100 hours (as defined in this section). pump, a gas flow meter, and an automated percent of the span value. 3.1.21 Grace Period means a specified data acquisition and handling system. The 3.1.12 Calibration Error Test means a test number of unit or stack operating hours after system samples the stack gas at a constant designed to assess the ability of a Hg CEMS the deadline for a required quality-assurance proportional rate relative to the stack gas to measure the concentrations of calibration test of a continuous monitor has passed, in volumetric flow rate. The sampling is a batch gases accurately. A zero-level gas and an which the test may be performed and passed process. The average Hg concentration in the upscale gas are required for this test. For the without loss of data. stack gas for the sampling period is upscale gas, either a mid-level gas or a high- 3.2 Continuous Monitoring Methods. determined, in units of micrograms per dry level gas may be used, and the gas may either 3.2.1 Hg CEMS. A typical Hg CEMS is standard cubic meter (mg/dscm), based on the be an elemental or oxidized Hg standard. shown in Figure A–1. The CEMS in Figure sample volume measured by the gas flow 3.1.13 Linearity Check means a test A–1 is a dilution extractive system, which meter and the mass of Hg collected in the designed to determine whether the response sorbent traps. of a Hg analyzer is linear across its measures Hg concentration on a wet basis, 3.1.3 NIST means the National Institute measurement range. Three elemental Hg and is the most commonly-used type of Hg of Standards and Technology, located in calibration gas standards (i.e., low, mid, and CEMS. Other system designs may be used, Gaithersburg, Maryland. high-level gases) are required for this test. provided that the CEMS meets the 3.1.4 NIST–Traceable Elemental Hg 3.1.14 System Integrity Check means a performance specifications in section 4.1.1 of Standards means either: compressed gas test designed to assess the transport and this appendix.

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3.2.1.1 Equipment Specifications. required for these operations are considered of material that is non-reactive to the gas 3.2.1.1.1 Materials of Construction. All to be conditioning equipment. For dry basis sampled and the calibration gas, and must be wetted sampling system components, measurements, a condenser, dryer or other configured to safely discharge any excess gas. including probe components prior to the suitable device is required to remove 3.2.1.1.3.8 Hg Analyzer. An instrument is point at which the calibration gas is moisture continuously from the sample gas, required that continuously measures the total introduced, must be chemically inert to all and any equipment needed to heat the probe vapor phase Hg concentration in the gas Hg species. Materials such as perfluoroalkoxy or sample line to avoid condensation prior to stream. The analyzer may also be capable of (PFA) TeflonTM, quartz, and treated stainless the moisture removal component is also measuring elemental and oxidized Hg steel (SS) are examples of such materials. required. separately. 3.2.1.1.2 Temperature Considerations. 3.2.1.1.3.5 Sampling Pump. A pump is 3.2.1.1.3.9 Data Recorder. A recorder, All system components prior to the Hg∂2 to needed to push or pull the sample gas such as a computerized data acquisition and Hg0 converter must be maintained at a through the system at a flow rate sufficient handling system (DAHS), digital recorder, or sample temperature above the acid gas dew to minimize the response time of the data logger, is required for recording point. measurement system. If a mechanical sample measurement data. 3.2.1.1.3 Measurement System pump is used and its surfaces are in contact 3.2.1.2 Reagents and Standards. Components. with the sample gas prior to detection, the 3.2.1.2.1 NIST Traceability. Only NIST- 3.2.1.1.3.1 Sample Probe. The probe must pump must be leak free and must be certified or NIST-traceable calibration gas be made of the appropriate materials as noted constructed of a material that is non-reactive standards and reagents (as defined in in paragraph 3.2.1.1.1 of this section, heated to the gas being sampled (see paragraph paragraphs 3.1.4 and 3.1.5 of this section) when necessary, as described in paragraph 3.2.1.1.1 of this section). For dilution-type shall be used for the tests and procedures 3.2.1.1.3.4 of this section, and configured measurement systems, such as the system required under this subpart. Calibration gases 0 with ports for introduction of calibration shown in Figure A–1, an ejector pump with known concentrations of Hg and HgCl2 gases. (eductor) may be used to create a sufficient are required. Special reagents and equipment 0 3.2.1.1.3.2 Filter or Other Particulate vacuum that sample gas will be drawn may be needed to prepare the Hg and HgCl2 Removal Device. The filter or other through a critical orifice at a constant rate. gas standards (e.g., NIST-traceable solutions particulate removal device is part of the The ejector pump must be constructed of any of HgCl2 and gas generators equipped with measurement system, must be made of material that is non-reactive to the gas being mass flow controllers). appropriate materials, as noted in paragraph sampled. 3.2.1.2.2 Required Calibration Gas 3.2.1.1.1 of this section, and must be 3.2.1.1.3.6 Calibration Gas System(s). Concentrations. included in all system tests. Design and equip each Hg CEMS to permit 3.2.1.2.2.1 Zero-Level Gas. A zero-level 3.2.1.1.3.3 Sample Line. The sample line the introduction of known concentrations of calibration gas with a Hg concentration that connects the probe to the converter, elemental Hg and HgCl2 separately, at a point below the level detectable by the Hg analyzer conditioning system, and analyzer must be preceding the sample extraction filtration is required for calibration error tests and made of appropriate materials, as noted in system, such that the entire measurement cycle time tests of the CEMS. paragraph 3.2.1.1.1 of this section. system can be checked. The calibration gas 3.2.1.2.2.2 Low-Level Gas. A low-level 3.2.1.1.3.4 Conditioning Equipment. For system(s) must be designed so that the flow calibration gas with a Hg concentration of 20 wet basis systems, such as the one shown in rate exceeds the sampling system flow to 30 percent of the span value is required Figure A–1, the sample must be kept above requirements and that the gas is delivered to for linearity checks and 3-level system its dew point either by: heating the sample the CEMS at atmospheric pressure. integrity checks of the CEMS. Elemental Hg line and all sample transport components up 3.2.1.1.3.7 Sample Gas Delivery. The standards are required for the linearity to the inlet of the analyzer (and, for hot-wet sample line may feed directly to either a checks and oxidized Hg standards are extractive systems, also heating the analyzer); converter, a by-pass valve (for Hg speciating required for the system integrity checks. or diluting the sample prior to analysis using systems), or a sample manifold. All valve 3.2.1.2.2.3 Mid-Level Gas. A mid-level a dilution probe system. The components and/or manifold components must be made calibration gas with a Hg concentration of 50

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to 60 percent of the span value is required Otherwise, round off the result to either: the All tests must be performed with the affected for linearity checks and for 3-level system next highest integer; the next highest unit(s) operating (i.e., combusting fuel). integrity checks of the CEMS, and is optional multiple of 5 mg/scm; or the next highest Except for the RATA, which must be for calibration error tests and single-level multiple of 10 mg/scm. performed at normal load, no particular load system integrity checks. Elemental Hg 3.2.1.4.3 Analyzer Range. The Hg level is required for the certification tests. standards are required for the linearity analyzer must be capable of reading Hg 4.1.1.1 7-Day Calibration Error Test. checks, oxidized Hg standards are required concentration as high as the MPC. Perform the 7-day calibration error test on 7 for the system integrity checks, and either 3.2.2 Sorbent Trap Monitoring System. A consecutive source operating days, using a elemental or oxidized Hg standards may be sorbent trap monitoring system (as defined in zero-level gas and either a high-level or a used for the calibration error tests. paragraph 3.1.2 of this section) may be used mid-level calibration gas standard (as defined 3.2.1.2.2.4 High-Level Gas. A high-level as an alternative to a Hg CEMS. If this option in sections 3.1.8, 3.1.10, and 3.1.11 of this calibration gas with a Hg concentration of 80 is selected, the monitoring system shall be appendix). Either elemental or oxidized to 100 percent of the span value is required installed, maintained, and operated in NIST-traceable Hg standards (as defined in for linearity checks, 3-level system integrity accordance with Performance Specification sections 3.1.4 and 3.1.5 of this appendix) checks, and cycle time tests of the CEMS, and (PS) 12B in Appendix B to part 60 of this may be used for the test. If moisture and/or is optional for calibration error tests and chapter. The system shall be certified in chlorine is added to the calibration gas, the single-level system integrity checks. accordance with the provisions of section dilution effect of the moisture and/or Elemental Hg standards are required for the 4.1.2 of this appendix. chlorine addition on the calibration gas linearity checks, oxidized Hg standards are 3.2.3 Other Necessary Data Collection. To concentration must be accounted for in an required for the system integrity checks, and convert measured hourly Hg concentrations appropriate manner. Operate the Hg CEMS in either elemental or oxidized Hg standards to the units of the applicable emissions its normal sampling mode during the test. may be used for the calibration error and standard (i.e., lb/TBtu or lb/GWh), additional The calibrations should be approximately 24 cycle time tests. data must be collected, as described in hours apart, unless the 7-day test is 3.2.1.3 Installation and Measurement paragraphs 3.2.3.1 through 3.2.3.3 of this performed over nonconsecutive calendar Location. For the Hg CEMS and any section. Any additional monitoring systems days. On each day of the test, inject the zero- additional monitoring system(s) needed to needed for this purpose must be certified, level and upscale gases in sequence and convert Hg concentrations to the desired operated, maintained, and quality-assured record the analyzer responses. Pass the units of measure (i.e., a flow monitor, CO2 or according to the applicable provisions of part calibration gas through all filters, scrubbers, O2 monitor, and/or moisture monitor, as 75 of this chapter (see §§ 63.10010(b) through conditioners, and other monitor components applicable), install each monitoring system at (d)). The calculation methods for the types of used during normal sampling, and through as a location: that is consistent with emission limits described in paragraphs much of the sampling probe as is practical. 63.10010(a); that represents the emissions 3.2.3.1 and 3.2.3.2 of this section are Do not make any manual adjustments to the exiting to the atmosphere; and where it is presented in section 6.2 of this appendix. monitor (i.e., resetting the calibration) until likely that the CEMS can pass the relative 3.2.3.1 Heat Input-Based Emission Limits. after taking measurements at both the zero accuracy test. For a heat input-based Hg emission limit (i.e., and upscale concentration levels. If 3.2.1.4 Monitor Span and Range in lb/TBtu), data from a certified CO2 or O2 automatic adjustments are made following Requirements. Determine the appropriate monitor are needed, along with a fuel- both injections, conduct the calibration error span and range value(s) for the Hg CEMS as specific F-factor and a conversion constant to test such that the magnitude of the described in paragraphs 3.2.1.4.1 through convert measured Hg concentration values to adjustments can be determined, and use only 3.2.1.4.3 of this section. the units of the standard. In some cases, the the unadjusted analyzer responses in the 3.2.1.4.1 Maximum Potential stack gas moisture content must also be calculations. Calculate the calibration error Concentration. There are three options for considered in making these conversions. (CE) on each day of the test, as described in determining the maximum potential Hg 3.2.3.2 Electrical Output-Based Emission Table A–1. The CE on each day of the test concentration (MPC). Option 1 applies to Rates. If the applicable Hg limit is electrical must either meet the main performance coal combustion. You may use a default output-based (i.e., lb/GWh), hourly electrical specification or the alternative specification value of 10 mg/scm for all coal ranks load data and unit operating times are in Table A–1. (including coal refuse) except for lignite; for required in addition to hourly data from a 4.1.1.2 Linearity Check. Perform the lignite, use 16 mg/scm. If different coals are certified stack gas flow rate monitor and (if linearity check using low, mid, and high- blended as part of normal operation, use the applicable) moisture data. level concentrations of NIST-traceable highest MPC for any fuel in the blend. Option 3.2.3.3 Sorbent Trap Monitoring System elemental Hg standards. Three gas injections 2 is to base the MPC on the results of site- Operation. Routine operation of a sorbent at each concentration level are required, with specific Hg emission testing. This option may trap monitoring system requires the use of a no two successive injections at the same be used only if the unit does not have add- certified stack gas flow rate monitor, to concentration level. Introduce the calibration on Hg emission controls or a flue gas maintain an established ratio of stack gas gas at the gas injection port, as specified in desulfurization system, or if testing is flow rate to sample flow rate. section 3.2.1.1.3.6 of this appendix. Operate performed upstream of all emission control the CEMS at its normal operating devices. If Option 2 is selected, perform at 4. Certification and Recertification temperature and conditions. Pass the least three test runs at the normal operating Requirements calibration gas through all filters, scrubbers, load, and the highest Hg concentration 4.1 Certification Requirements. All Hg conditioners, and other components used obtained in any of the tests shall be the MPC. CEMS and sorbent trap monitoring systems during normal sampling, and through as Option 3 is to use fuel sampling and analysis and the additional monitoring systems used much of the sampling probe as is practical. to estimate the MPC. To make this estimate, to continuously measure Hg emissions in If moisture and/or chlorine is added to the use the average Hg content (i.e., the weight units of the applicable emissions standard in calibration gas, the dilution effect of the percentage) from at least three representative accordance with this appendix must be moisture and/or chlorine addition on the fuel samples, together with other available certified in a timely manner, such that the calibration gas concentration must be information, including, but not limited to the initial compliance demonstration is accounted for in an appropriate manner. maximum fuel feed rate, the heating value of completed no later than the applicable date Record the monitor response from the data the fuel, and an appropriate F-factor. Assume in § 63.10005(g). acquisition and handling system for each gas that all of the Hg in the fuel is emitted to the 4.1.1 Hg CEMS. Table A–1, below, injection. At each concentration level, use atmosphere as vapor-phase Hg. summarizes the certification test the average analyzer response to calculate the 3.2.1.4.2 Span Value. To determine the requirements and performance specifications linearity error (LE), as described in Table A– span value of the Hg CEMS, multiply the Hg for a Hg CEMS. The CEMS may not be used 1. The LE must either meet the main concentration corresponding to the to report quality-assured data until these performance specification or the alternative applicable emissions standard by two. If the performance criteria are met. Paragraphs specification in Table A–1. result of this calculation is an exact multiple 4.1.1.1 through 4.1.1.5 of this section provide 4.1.1.3 Three-Level System Integrity of 10 mg/scm, use the result as the span value. specific instructions for the required tests. Check. Perform the 3-level system integrity

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check using low, mid, and high-level to the calibration gas, the dilution effect of described in Table A–1. The SIE must either calibration gas concentrations generated by a the moisture and/or chlorine addition on the meet the main performance specification or NIST-traceable source of oxidized Hg. Follow calibration gas concentration must be the alternative specification in Table A–1. the same basic procedure as for the linearity accounted for in an appropriate manner. (Note: This test is not required if the CEMS check. If moisture and/or chlorine is added Calculate the system integrity error (SIE), as does not have a converter).

TABLE A–1—REQUIRED CERTIFICATION TESTS AND PERFORMANCE SPECIFICATIONS FOR Hg CEMS

For this required certification test The main performance specifica- The alternate performance speci- And the conditions of the alter- ... tion 1 is . . . fication 1 is . . . nate specification are . . .

7-day calibration error test 2 ...... ⎢R ¥ A ⎢ ≤5.0% of span value, for ⎢R ¥ A ⎢ ≤1.0 μg/scm ...... The alternate specification may both the zero and upscale be used on any day of the test. gases, on each of the 7 days. 3 Linearity check ...... ⎢R ¥ Aavg ⎢ ≤10.0% of the ref- ⎢R ¥ Aavg ⎢ ≤0.8 μg/scm ...... The alternate specification may erence gas concentration at be used at any gas level. each calibration gas level (low, mid, or high). 4 3-level system integrity check ..... ⎢R ¥ Aavg ⎢ ≤10.0% of the ref- ⎢R ¥ Aavg ⎢ ≤0.8 μg/scm ...... The alternate specification may erence gas concentration at be used at any gas level. each calibration gas level. RATA ...... 20.0% RA ...... ⎢RMavg ¥ Cavg ⎢ ≤1.0 μg/scm** .... RMavg <5.0 μg/scm. Cycle time test 2 ...... 15 minutes.5

1 Note that ⎢R ¥ A ⎢ is the absolute value of the difference between the reference gas value and the analyzer reading. ⎢R ¥ Aavg, ⎢ is the ab- solute value of the difference between the reference gas concentration and the average of the analyzer responses, at a particular gas level. 2 Use either elemental or oxidized Hg standards; a mid-level or high-level upscale gas may be used. This test is not required for Hg CEMS that use integrated batch sampling; however, those monitors must be capable of recording at least one Hg concentration reading every 15 minutes. 3 Use elemental Hg standards. 4 Use oxidized Hg standards. Not required if the CEMS does not have a converter. 5 Stability criteria—Readings change by <2.0% of span or by ≤0.5 μg/scm, for 2 minutes. ** Note that ⎢RMavg¥Cavg ⎢ is the absolute difference between the mean reference method value and the mean CEMS value from the RATA. The arithmetic difference between RMavg and Cavg can be either + or ¥.

4.1.1.4 Cycle Time Test. Perform the Sources (Ontario Hydro Method)’’ data must be reported including the rejected cycle time test, using a zero-level gas and a (incorporated by reference, see § 63.14) and data. The minimum time per run is 21 high-level calibration gas. Methods 29, 30A, and 30B in appendix A– minutes if Method 30A is used. If Method 29, Either an elemental or oxidized NIST- 8 to part 60. When Method 29 or ASTM Method 30B, or ASTM D6784–02 traceable Hg standard may be used as the D6784–02 is used, paired sampling trains are (Reapproved 2008), ‘‘Standard Test Method high-level gas. Perform the test in two required. To validate a Method 29 or ASTM for Elemental, Oxidized, Particle-Bound and stages—upscale and downscale. The slower D6784–02 test run, calculate the relative Total Mercury in Flue Gas Generated from of the upscale and downscale response times deviation (RD) using Equation A–1 of this Coal-Fired Stationary Sources (Ontario Hydro is the cycle time for the CEMS. Begin each section, and assess the results as follows to Method)’’ (incorporated by reference, see stage of the test by injecting calibration gas validate the run. The RD must not exceed 10 § 63.14) is used, the time per run must be after achieving a stable reading of the stack percent, when the average Hg concentration long enough to collect a sufficient mass of Hg emissions. The cycle time is the amount of is greater than 1.0 mg/dscm. If the average to analyze. Complete the RATA within 168 time it takes for the analyzer to register a concentration is ≤ 1.0 mg/dscm, the RD must unit operating hours, except when Method 29 reading that is 95 percent of the way between not exceed 20 percent. The RD results are or ASTM D6784–02 is used, in which case the stable stack emissions reading and the also acceptable if the absolute difference up to 336 operating hours may be taken to final, stable reading of the calibration gas between the two Hg concentrations does not finish the test. concentration. Use the following criterion to exceed 0.2 mg/dscm. If the RD specification 4.1.1.5.2 Calculation of RATA Results. determine when a stable reading of stack is met, the results of the two samples shall Calculate the relative accuracy (RA) of the emissions or calibration gas has been be averaged arithmetically. monitoring system, on a mg/scm basis, as attained—the reading is stable if it changes described in section 12 of Performance by no more than 2.0 percent of the span value Specification (PS) 2 in Appendix B to part 60 or 0.5 mg/scm (whichever is less restrictive) of this chapter (see Equations 2–3 through 2– for two minutes, or a reading with a change 6 of PS2). For purposes of calculating the of less than 6.0 percent from the measured relative accuracy, ensure that the reference average concentration over 6 minutes. Where: method and monitoring system data are on a Integrated batch sampling type Hg CEMS are RD = Relative deviation between the Hg consistent moisture basis, either wet or dry. exempted from this test; however, these concentrations of samples ‘‘a’’ and ‘‘b’’ The CEMS must either meet the main systems must be capable of delivering a (percent) performance specification or the alternative measured Hg concentration reading at least specification in Table A–1. Ca = Hg concentration of Hg sample ‘‘a’’ (mg/ once every 15 minutes. If necessary to dscm) 4.1.1.5.3 Bias Adjustment. Measurement increase measurement sensitivity of a batch or adjustment of Hg CEMS data for bias is not Cb = Hg concentration of Hg sample ‘‘b’’ (mg/ sampling type Hg CEMS for a specific dscm) required. application, you may petition the 4.1.2 Sorbent Trap Monitoring Systems. Administrator for approval of a time longer 4.1.1.5.1 Special Considerations. A For the initial certification of a sorbent trap than 15 minutes between readings. minimum of nine valid test runs must be monitoring system, only a RATA is required. 4.1.1.5 Relative Accuracy Test Audit performed, directly comparing the CEMS 4.1.2.1 Reference Methods. The (RATA). Perform the RATA of the Hg CEMS measurements to the reference method. More acceptable reference methods for the RATA at normal load. Acceptable Hg reference than nine test runs may be performed. If this of a sorbent trap monitoring system are the methods for the RATA include ASTM option is chosen, the results from a same as those listed in paragraph 4.1.1.5 of D6784–02 (Reapproved 2008), ‘‘Standard maximum of three test runs may be rejected this section. Test Method for Elemental, Oxidized, so long as the total number of test results 4.1.2.2 ‘‘The special considerations Particle-Bound and Total Mercury in Flue used to determine the relative accuracy is specified in paragraph 4.1.1.5.1 of this Gas Generated from Coal-Fired Stationary greater than or equal to nine; however, all section apply to the RATA of a sorbent trap

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monitoring system. During the RATA, the modification, or change to the flue gas 5.1.2.4 The test frequency for the RATAs monitoring system must be operated and handling system or the unit operation that of the Hg CEMS shall be annual, i.e., once quality-assured in accordance with may significantly change the concentration or every four QA operating quarters. For units Performance Specification (PS) 12B in flow profile, the owner or operator shall that operate infrequently, extensions of Appendix B to part 60 of this chapter with recertify the monitoring system. The same RATA deadlines are allowed for non-QA the following exceptions for sorbent trap tests performed for the initial certification of operating quarters. Following a RATA, if section 2 breakthrough: the monitoring system shall be repeated for there is a subsequent non-QA quarter, it 4.1.2.2.1 For stack Hg concentrations >1 recertification, unless otherwise specified by extends the deadline for the next test by one ≤ mg/dscm, 10% of section 1 Hg mass; the Administrator. Examples of changes that calendar quarter. However, there is a limit to ≤ 4.1.2.2.2 For stack Hg concentrations 1 require recertification include: replacement these extensions; the deadline may not be ≤ mg/dscm and >0.5 mg/dscm, 20% of section of a gas analyzer; complete monitoring extended beyond the end of the eighth 1 Hg mass; system replacement, and changing the calendar quarter after the quarter of the last 4.1.2.2.3 For stack Hg concentrations ≤0.5 location or orientation of the sampling probe. ≤ test. At that point, a RATA must either be mg/dscm and >0.1 mg/dscm, 50% of section 5. Ongoing Quality Assurance (QA) and Data performed within the eighth calendar quarter 1 Hg mass; and Validation or in a 720 hour unit or stack operating hour 4.1.2.2.4 For stack Hg concentrations grace period following that quarter. When a ≤ m 5.1 Hg CEMS. 0.1 g/dscm, no breakthrough criterion required annual RATA is done within a grace assuming all other QA/QC specifications are 5.1.1 Required QA Tests. Periodic QA period, the deadline for the next RATA is met. testing of each Hg CEMS is required three QA operating quarters after the quarter 4.1.2.3 The type of sorbent material used following initial certification. The required in which the grace period test is performed. by the traps during the RATA must be the QA tests, the test frequencies, and the 5.1.3 Grace Periods. same as for daily operation of the monitoring performance specifications that must be met 5.1.3.1 A 168 unit or stack operating hour system; however, the size of the traps used are summarized in Table A–2, below. All grace period is available for quarterly for the RATA may be smaller than the traps tests must be performed with the affected linearity checks and 3-level system integrity used for daily operation of the system. unit(s) operating (i.e., combusting fuel). 4.1.2.4 Calculation of RATA Results. Except for the RATA, which must be checks of the Hg CEMS. Calculate the relative accuracy (RA) of the performed at normal load, no particular load 5.1.3.2 A 720 unit or stack operating hour sorbent trap monitoring system, on a mg/scm level is required for the tests. For each test, grace period is available for RATAs of the Hg follow the same basic procedures in section basis, as described in section 12 of CEMS. 4.1.1 of this appendix that were used for Performance Specification (PS) 2 in appendix 5.1.3.3 There is no grace period for initial certification. B to part 60 of this chapter (see Equations 2– weekly system integrity checks. The test 5.1.2 Test Frequency. The frequency for 3 through 2–6 of PS2). For purposes of must be completed once every 7 operating the required QA tests of the Hg CEMS shall calculating the relative accuracy, ensure that days. be as follows: 5.1.4 Data Validation. The Hg CEMS is the reference method and monitoring system 5.1.2.1 Calibration error tests of the Hg data are on a consistent moisture basis, either considered to be out-of-control, and data CEMS are required daily, except during unit from the CEMS may not be reported as wet or dry.The main and alternative RATA outages. Use either NIST-traceable elemental performance specifications in Table A–1 for quality-assured, when any one of the Hg standards or NIST-traceable oxidized Hg acceptance criteria for the required QA tests Hg CEMS also apply to the sorbent trap standards for these calibrations. Both a zero- monitoring system. in Table A–2 is not met. The CEMS is also level gas and either a mid-level or high-level considered to be out-of-control when a 4.1.2.5 Bias Adjustment. Measurement or gas are required for these calibrations. required QA test is not performed on adjustment of sorbent trap monitoring system 5.1.2.2 Perform a linearity check of the schedule or within an allotted grace period. data for bias is not required. Hg CEMS in each QA operating quarter, To end an out-of-control period, the QA test 4.1.3 Diluent Gas, Flow Rate, and/or using low-level, mid-level, and high-level that was either failed or not done on time Moisture Monitoring Systems. Monitoring NIST-traceable elemental Hg standards. For must be performed and passed. Out-of- systems that are used to measure stack gas units that operate infrequently, limited volumetric flow rate, diluent gas exemptions from this test are allowed for control periods are counted as hours of concentration, or stack gas moisture content, ‘‘non-QA operating quarters’’. A maximum of monitoring system downtime. either for routine operation of a sorbent trap three consecutive exemptions for this reason 5.1.5 Conditional Data Validation. For monitoring system or to convert Hg are permitted, following the quarter of the certification, recertification, and diagnostic concentration data to units of the applicable last test. After the third consecutive testing of Hg monitoring systems, and for the emission limit, must be certified in exemption, a linearity check must be required QA tests when non-redundant accordance with the applicable provisions of performed in the next calendar quarter or backup Hg monitoring systems or temporary part 75 of this chapter. within a grace period of 168 unit or stack like-kind Hg analyzers are brought into 4.2 Recertification. Whenever the owner operating hours after the end of that quarter. service, the conditional data validation or operator makes a replacement, The test frequency for 3-level system provisions in §§ 75.20(b)(3)(ii) through modification, or change to a certified CEMS integrity checks (if performed in lieu of (b)(3)(ix) of this chapter may be used to avoid or sorbent trap monitoring system that may linearity checks) is the same as for the or minimize data loss. The allotted window significantly affect the ability of the system linearity checks. Use low-level, mid-level, of time to complete 7-day calibration error to accurately measure or record pollutant or and high-level NIST-traceable oxidized Hg tests, linearity checks, cycle time tests, and diluent gas concentrations, stack gas flow standards for the system integrity checks. RATAs shall be as specified in rates, or stack gas moisture content, the 5.1.2.3 If required, perform a single-level § 75.20(b)(3)(iv) of this chapter. Required owner or operator shall recertify the system integrity check weekly, i.e., once system integrity checks must be completed monitoring system. Furthermore, whenever every 7 operating days (see the third column within 168 unit or stack operating hours after the owner or operator makes a replacement, in Table A–2). the probationary calibration error test.

TABLE A–2—ON-GOING QA TEST REQUIREMENTS FOR Hg CEMS

With these qualifications and ex- Perform this type of QA test . . . At this frequency . . . ceptions . . . Acceptance criteria . . .

Calibration error test ...... Daily ...... • Use either a mid- or high-level ⎢R¥A ⎢ ≤ 5.0% of span value. gas. or ⎢R¥A ⎢ ≤ 1.0 μg/scm. • Use either elemental or oxidized Hg.

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TABLE A–2—ON-GOING QA TEST REQUIREMENTS FOR Hg CEMS—Continued

With these qualifications and ex- Perform this type of QA test . . . At this frequency . . . ceptions . . . Acceptance criteria . . .

• Calibrations are not required when the unit is not in oper- ation. 1 Single-level system integrity check Weekly ...... • Required only for systems with ⎢R¥Aavg ⎢ ≤ 10.0% of the ref- converters. erence gas value. or ⎢R¥Aavg ⎢ ≤ 0.8 μg/scm. • Use oxidized Hg—either mid- or high-level. • Not required if daily calibrations are done with a NIST-traceable source of oxidized Hg. 3 Linearity check Quarterly ...... • Required in each ‘‘QA operating ⎢R¥Aavg ⎢ ≤ 10.0% of the ref- or quarter’’ 2—and no less than erence gas value, at each cali- 3-level system integrity check once every 4 calendar quarters. bration gas level. or ⎢R¥Aavg ⎢ ≤ 0.8 μg/scm. • 168 operating hour grace pe- riod available. • Use elemental Hg for linearity check. • Use oxidized Hg for system in- tegrity check. • For system integrity check, CEMS must have a converter. RATA ...... Annual 4 ...... • Test deadline may be extended 20.0% RA. for ‘‘non-QA operating quar- or ters’’, up to a maximum of 8 ⎢RMavg¥Cavg ⎢ ≤ 1.0 μg/scm, quarters from the quarter of the if previous test. RMavg < 5.0 μg/scm. • 720 operating hour grace pe- riod available. 1 ‘‘Weekly’’ means once every 7 operating days. 2 A ‘‘QA operating quarter’’ is a calendar quarter with at least 168 unit or stack operating hours. 3 ‘‘Quarterly’’ means once every QA operating quarter. 4 ‘‘Annual’’ means once every four QA operating quarters.

5.1.6 Adjustment of Span. If you discover 5.2.2.3 A 720 unit or stack operating hour are specified in section 1 of appendix B to that a span adjustment is needed (e.g., if the grace period is available for RATAs of the part 75 of this chapter. Hg concentration readings exceed the span monitoring system. 5.4.1 General Requirements. value for a significant percentage of the unit 5.2.3 Data validation for sorbent trap 5.4.1.1 Preventive Maintenance. Keep a operating hours in a calendar quarter), you monitoring systems shall be done in written record of procedures needed to must implement the span adjustment within accordance with Table 12B–1 in Performance maintain the Hg CEMS and/or sorbent trap 90 days after the end of the calendar quarter Specification (PS) 12B in appendix B to part monitoring system(s) in proper operating in which you identify the need for the 60 of this chapter. All periods of invalid data condition and a schedule for those adjustment. A diagnostic linearity check is shall be counted as hours of monitoring procedures. Include, at a minimum, all required within 168 unit or stack operating system downtime. procedures specified by the manufacturers of hours after changing the span value. 5.3 Flow Rate, Diluent Gas, and Moisture the equipment and, if applicable, additional 5.2 Sorbent Trap Monitoring Systems. Monitoring Systems. The on-going QA test or alternate procedures developed for the 5.2.1 Each sorbent trap monitoring requirements for these monitoring systems equipment. system shall be continuously operated and are specified in part 75 of this chapter (see 5.4.1.2 Recordkeeping and Reporting. maintained in accordance with Performance §§ 63.10010(b) through (d)). Keep a written record describing procedures Specification (PS) 12B in appendix B to part 5.4 QA/QC Program Requirements. The that will be used to implement the 60 of this chapter. The QA/QC criteria for owner or operator shall develop and recordkeeping and reporting requirements of routine operation of the system are implement a quality assurance/quality this appendix. summarized in Table 12B–1 of PS 12B. Each control (QA/QC) program for the Hg CEMS 5.4.1.3 Maintenance Records. Keep a pair of sorbent traps may be used to sample and/or sorbent trap monitoring systems that record of all testing, maintenance, or repair the stack gas for up to 14 operating days. are used to provide data under this subpart. activities performed on any Hg CEMS or 5.2.2 For ongoing QA, periodic RATAs of At a minimum, the program shall include a sorbent trap monitoring system in a location the system are required. written plan that describes in detail (or that and format suitable for inspection. A 5.2.2.1 The RATA frequency shall be refers to separate documents containing) maintenance log may be used for this annual, i.e., once every four QA operating complete, step-by-step procedures and purpose. The following records should be quarters. The provisions in section 5.1.2.4 of operations for the most important QA/QC maintained: date, time, and description of this appendix pertaining to RATA deadline activities. Electronic storage of the QA/QC any testing, adjustment, repair, replacement, extensions also apply to sorbent trap plan is permissible, provided that the or preventive maintenance action performed monitoring systems. information can be made available in hard on any monitoring system and records of any 5.2.2.2 The same RATA performance copy to auditors and inspectors. The QA/QC corrective actions associated with a monitor criteria specified in Table A–4 for Hg CEMS program requirements for the diluent gas, outage period. Additionally, any adjustment shall apply to the annual RATAs of the flow rate, and moisture monitoring systems that may significantly affect a system’s ability sorbent trap monitoring system. described in section 3.2.1.3 of this appendix to accurately measure emissions data must be

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recorded (e.g., changing the dilution ratio of a reference flow meter, the QA plan must convert Hg concentration values to the a CEMS), and a written explanation of the include a protocol for ongoing maintenance appropriate units of the emission standard. procedures used to make the adjustment(s) and periodic recalibration to maintain the 6.2.1 Heat Input-Based Hg Emission shall be kept. accuracy and NIST-traceability of the Rates. Calculate hourly heat input-based Hg 5.4.2 Specific Requirements for Hg CEMS. calibrator. emission rates, in units of lb/TBtu, according 5.4.2.1 Daily Calibrations, Linearity 5.4.3.3 Hg Analysis. Explain the chain of to sections 6.2.1.1 through 6.2.1.4 of this Checks and System Integrity Checks. Keep a custody employed in packing, transporting, appendix. written record of the procedures used for and analyzing the sorbent traps. Keep records 6.2.1.1 Select an appropriate emission daily calibrations of the Hg CEMS. If of all Hg analyses. The analyses shall be rate equation from among Equations 19–1 moisture and/or chlorine is added to the Hg performed in accordance with the procedures through 19–9 in EPA Method 19 in appendix calibration gas, document how the dilution described in section 11.0 of Performance A–7 to part 60 of this chapter. effect of the moisture and/or chlorine Specification (PS) 12B in Appendix B to part 6.2.1.2 Calculate the Hg emission rate in addition on the calibration gas concentration 60 of this chapter. lb/MMBtu, using the equation selected from is accounted for in an appropriate manner. 5.4.3.4 Data Collection Period. State, and Method 19. Multiply the Hg concentration Also keep records of the procedures used to provide the rationale for, the minimum value by 6.24 × 10¥11 to convert it from mg/ perform linearity checks of the Hg CEMS and acceptable data collection period (e.g., one scm to lb/scf. In cases where an appropriate the procedures for system integrity checks of day, one week, etc.) for the size of sorbent F-factor is not listed in Table 19–2 of Method the Hg CEMS. Document how the test results trap selected for the monitoring. Address 19, you may use F-factors from Table 1 in are calculated and evaluated. such factors as the Hg concentration in the section 3.3.5 of appendix F to part 75 of this 5.4.2.2 Monitoring System Adjustments. stack gas, the capacity of the sorbent trap, chapter, or F-factors derived using the Document how each component of the Hg and the minimum mass of Hg required for the procedures in section 3.3.6 of appendix to CEMS will be adjusted to provide correct analysis. Each pair of sorbent traps may be part 75 of this chapter. Also, for startup and responses to calibration gases after routine used to sample the stack gas for up to 14 shutdown hours, you may calculate the Hg maintenance, repairs, or corrective actions. operating days. emission rate using the applicable diluent 5.4.2.3 Relative Accuracy Test Audits. 5.4.3.5 Relative Accuracy Test Audit cap value specified in section 3.3.4.1 of Keep a written record of procedures used for Procedures. Keep records of the procedures RATAs of the Hg CEMS. Indicate the and details peculiar to the sorbent trap appendix F to part 75 of this chapter, reference methods used and document how monitoring systems that are to be followed provided that the diluent gas monitor is not the test results are calculated and evaluated. for relative accuracy test audits, such as out-of-control and the hourly average O2 5.4.3 Specific Requirements for Sorbent sampling and analysis methods. concentration is above 14.0% O2 (19.0% for Trap Monitoring Systems. an IGCC) or the hourly average CO2 5.4.3.1 Sorbent Trap Identification and 6. Data Reduction and Calculations concentration is below 5.0% CO2 (1.0% for Tracking. Include procedures for inscribing 6.1 Data Reduction. an IGCC), as applicable. or otherwise permanently marking a unique 6.1.1 Reduce the data from Hg CEMS to 6.2.1.3 Multiply the lb/MMBtu value identification number on each sorbent trap, hourly averages, in accordance with obtained in section 6.2.1.2 of this appendix for chain of custody purposes. Keep records § 60.13(h)(2) of this chapter. by 106 to convert it to lb/TBtu. of the ID of the monitoring system in which 6.1.2 For sorbent trap monitoring 6.2.1.4 The heat input-based Hg emission each sorbent trap is used, and the dates and systems, determine the Hg concentration for rate limit in Table 2 to this subpart must be hours of each Hg collection period. each data collection period and assign this met on a 30 boiler operating day rolling 5.4.3.2 Monitoring System Integrity and concentration value to each operating hour in average basis. Use Equation 19–19 in EPA Data Quality. Document the procedures used the data collection period. Method 19 to calculate the Hg emission rate to perform the leak checks when a sorbent 6.1.3 For any operating hour in which for each averaging period. The term Ehj in trap is placed in service and removed from valid data are not obtained, either for Hg Equation 19–19 must be in the units of the service. Also Document the other QA concentration or for a parameter used in the applicable emission limit. Do not include procedures used to ensure system integrity emissions calculations (i.e., flow rate, diluent non-operating hours with zero emissions in and data quality, including, but not limited gas concentration, or moisture, as the average. to, gas flow meter calibrations, verification of applicable), do not calculate the Hg emission 6.2.2 Electrical Output-Based Hg moisture removal, and ensuring air-tight rate for that hour. For the purposes of this Emission Rates. Calculate electrical output- pump operation. In addition, the QA plan appendix, part 75 substitute data values are based Hg emission limits in units of lb/GWh, must include the data acceptance and quality not considered to be valid data. according to sections 6.2.2.1 through 6.2.2.3 control criteria in Table 12B–1 in section 9.0 6.1.4 Operating hours in which valid data of this appendix. of Performance Specification (PS) 12B in are not obtained for Hg concentration are 6.2.2.1 Calculate the Hg mass emissions Appendix B to part 60 of this chapter. All considered to be hours of monitor downtime. for each operating hour in which valid data reference meters used to calibrate the gas The use of substitute data for Hg are obtained for all parameters, using flow meters (e.g., wet test meters) shall be concentration is not required. Equation A–2 of this section (for wet-basis periodically recalibrated. Annual, or more 6.2 Calculation of Hg Emission Rates. Use measurements of Hg concentration) or frequent, recalibration is recommended. If a the applicable calculation methods in Equation A–3 of this section (for dry-basis NIST-traceable calibration device is used as paragraphs 6.2.1 and 6.2.2 of this section to measurements), as applicable:

¥11 Where: K = Units conversion constant, 6.24 × 10 Qh = Stack gas volumetric flow rate for the lb-scm/mg-scf, hour (scfh). Mh = Hg mass emission rate for the hour (lb/ h) Ch = Hourly average Hg concentration, wet (Note: Use unadjusted flow rate values; basis (mg/scm) bias adjustment is not required)

¥11 Where: Mh = Hg mass emission rate for the hour (lb/ K = Units conversion constant, 6.24 x 10 h) lb-scm/mg-scf.

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Ch = Hourly average Hg concentration, dry (Note: Use unadjusted flow rate values; bias 6.2.2.2 Use Equation A–4 of this section basis (mg/dscm). adjustment is not required). to calculate the emission rate for each unit Qh = Stack gas volumetric flow rate for the Bws = Moisture fraction of the stack gas, or stack operating hour in which valid data hour (scfh) expressed as a decimal (equal to % H2O/ are obtained for all parameters. 100)

Where: (MW)h = Gross electrical load for the hour, to this subpart must be met on a 30-boiler

Eho = Electrical output-based Hg emission in megawatts (MW). operating day rolling average basis. Use rate (lb/GWh). 10 3 = Conversion factor from megawatts to Equation A–5 of this section to calculate the Mh = Hg mass emission rate for the hour, gigawatts. Hg emission rate for each averaging period. from Equation A–2 or A–3 of this 6.2.2.3 The applicable electrical output- section, as applicable (lb/h). based Hg emission rate limit in Table 1 or 2

Where: handling system or the flue gas handling input to the unit(s), but no electrical load,

E¯ o = Hg emission rate for the averaging system) which affects information reported in record only the items in paragraphs 7.1.2.1, period (lb/GWh). the monitoring plan (e.g., a change to a serial 7.1.2.2, and (if applicable) 7.1.2.4 of this Eho = Electrical output-based hourly Hg number for a component of a monitoring section. emission rate for unit or stack operating system), the owner or operator shall update 7.1.2.1 The date and hour; hour ‘‘h’’ in the averaging period, from the monitoring plan. 7.1.2.2 The unit or stack operating time Equation A–4 of this section (lb/GWh). 7.1.1.2 Contents of the Monitoring Plan. (rounded up to the nearest fraction of an hour n = Number of unit or stack operating hours For Hg CEMS and sorbent trap monitoring (in equal increments that can range from one in the averaging period in which valid systems, the monitoring plan shall contain hundredth to one quarter of an hour, at the data were obtained for all parameters the information in sections 7.1.1.2.1 and option of the owner or operator); (Note: Do not include non-operating 7.1.1.2.2 of this appendix, as applicable. For 7.1.2.3 The hourly gross unit load hours with zero emission rates in the stack gas flow rate, diluent gas, and moisture (rounded to nearest MWe); and average). monitoring systems, the monitoring plan 7.1.2.4 If applicable, the F-factor used to shall include the information required for calculate the heat input-based Hg emission 7. Recordkeeping and Reporting those systems under § 75.53 (g) of this rate. 7.1 Recordkeeping Provisions. For the Hg chapter. 7.1.3 Hg Emissions Records (Hg CEMS). CEMS and/or sorbent trap monitoring 7.1.1.2.1 Electronic. The electronic For each affected unit or common stack using systems and any other necessary monitoring monitoring plan records must include the a Hg CEMS, the owner or operator shall systems installed at each affected unit, the following: unit or stack ID number(s); record the following information for each owner or operator must maintain a file of all monitoring location(s); the Hg monitoring unit or stack operating hour: methodologies used; Hg monitoring system 7.1.3.1 The date and hour; measurements, data, reports, and other information, including, but not limited to: 7.1.3.2 Monitoring system and information required by this appendix in a Unique system and component ID numbers; component identification codes, as provided form suitable for inspection, for 5 years from the make, model, and serial number of the in the monitoring plan, if the CEMS provides the date of each record, in accordance with monitoring equipment; the sample a quality-assured value of Hg concentration § 63.10033. The file shall contain the acquisition method; formulas used to for the hour; information in paragraphs 7.1.1 through calculate Hg emissions; Hg monitor span and 7.1.3.3 The hourly Hg concentration, if a 7.1.10 of this section. range information The electronic monitoring quality-assured value is obtained for the hour 7.1.1 Monitoring Plan Records. For each plan shall be evaluated and submitted using (mg/scm, rounded to three significant figures); affected unit or group of units monitored at the Emissions Collection and Monitoring 7.1.3.4 A special code, indicating a common stack, the owner or operator shall Plan System (ECMPS) Client Tool provided whether or not a quality-assured Hg prepare and maintain a monitoring plan for by the Clean Air Markets Division in the concentration is obtained for the hour. This the Hg CEMS and/or sorbent trap monitoring Office of Atmospheric Programs of the EPA. code may be entered manually when a system(s) and any other monitoring system(s) 7.1.1.2.2 Hard Copy. Keep records of the temporary like-kind replacement Hg analyzer (i.e., flow rate, diluent gas, or moisture following: schematics and/or blueprints is used for reporting; and systems) needed for routine operation of a showing the location of the Hg monitoring 7.1.3.5 Monitor data availability, as a sorbent trap monitoring system or to convert system(s) and test ports; data flow diagrams; percentage of unit or stack operating hours, Hg concentrations to units of the applicable test protocols; monitor span and range calculated according to § 75.32 of this emission standard. The monitoring plan shall calculations; miscellaneous technical chapter. contain essential information on the justifications. 7.1.4 Hg Emissions Records (Sorbent continuous monitoring systems and shall 7.1.2 Operating Parameter Records. The Trap Monitoring Systems). For each affected Document how the data derived from these owner or operator shall record the following unit or common stack using a sorbent trap systems ensure that all Hg emissions from the information for each operating hour of each monitoring system, each owner or operator unit or stack are monitored and reported. affected unit and also for each group of units shall record the following information for the 7.1.1.1 Updates. Whenever the owner or utilizing a common stack, to the extent that unit or stack operating hour in each data operator makes a replacement, modification, these data are needed to convert Hg collection period: or change in a certified continuous concentration data to the units of the 7.1.4.1 The date and hour; monitoring system that is used to provide emission standard. For non-operating hours, 7.1.4.2 Monitoring system and data under this subpart (including a change record only the items in paragraphs 7.1.2.1 component identification codes, as provided in the automated data acquisition and and 7.1.2.2 of this section. If there is heat in the monitoring plan, if the sorbent trap

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system provides a quality-assured value of system that meets the requirements of part 75 Hg CEMS and/or sorbent trap monitoring Hg concentration for the hour; of this chapter, to record the required data. systems; 7.1.4.3 The hourly Hg concentration, if a If you use a moisture monitoring system, you 7.1.9.4 The stable stack gas and quality-assured value is obtained for the hour must keep hourly records of the stack gas calibration gas readings and the calculated (mg/scm, rounded to three significant figures). moisture content, as specified in § 75.57(c)(3) results for the upscale and downscale stages Note that when a quality-assured Hg of this chapter. of all required cycle time tests of the Hg concentration value is obtained for a 7.1.7 Records of Diluent Gas (CO2 or O2) CEMS or, for a batch sampling Hg CEMS, the particular data collection period, that single Concentration. interval between measured Hg concentration concentration value is applied to each 7.1.7.1 When a heat input-based Hg mass readings; operating hour of the data collection period. emissions limit must be met, in units of lb/ 7.1.9.5 Supporting information for all 7.1.4.4 A special code, indicating TBtu, hourly measurements of CO2 or O2 required RATAs of the Hg monitoring whether or not a quality-assured Hg concentration are required to convert Hg systems, including records of the test dates, concentration is obtained for the hour; concentrations to units of the standard. the raw reference method and monitoring 7.1.4.5 The average flow rate of stack gas 7.1.7.2 If hourly measurements of diluent system data, the results of sample analyses to through each sorbent trap (in appropriate gas concentration are needed, use a certified substantiate the reported test results, and units, e.g., liters/min, cc/min, dscm/min); CO2 or O2 monitor that meets the records of sampling equipment calibrations; 7.1.4.6 The gas flow meter reading (in requirements of part 75 of this chapter to 7.1.9.6 For sorbent trap monitoring dscm, rounded to the nearest hundredth), at record the required data. You must keep systems, also keep records of the results of the beginning and end of the collection hourly CO2 or O2 concentration records, as all analyses of the sorbent traps used for period and at least once in each unit specified in § 75.57(g) of this chapter. routine daily operation of the system, and operating hour during the collection period; 7.1.8 Hg Emission Rate Records. For information documenting the results of all 7.1.4.7 The ratio of the stack gas flow rate applicable Hg emission limits in units of leak checks and the other applicable quality to the sample flow rate, as described in lb/TBtu or lb/GWh, record the following control procedures described in Table 12B– section 12.2 of Performance Specification information for each affected unit or common 1 of Performance Specification (PS) 12B in (PS) 12B in Appendix B to part 60 of this stack: appendix B to part 60 of this chapter. chapter; and 7.1.8.1 The date and hour; 7.1.9.7 For stack gas flow rate, diluent 7.1.4.8 Monitor data availability, as a 7.1.8.2 The hourly Hg emissions rate gas, and (if applicable) moisture monitoring percentage of unit or stack operating hours, (lb/TBtu or lb/GWh, as applicable, calculated systems, you must keep records of all calculated according to § 75.32 of this according to section 6.2.1 or 6.2.2 of this certification, recertification, diagnostic, and chapter. appendix, rounded to three significant on-going quality-assurance tests of these 7.1.5 Stack Gas Volumetric Flow Rate figures), if valid values of Hg concentration systems, as specified in § 75.59 of this Records. and all other required parameters (stack gas chapter. 7.1.5.1 Hourly measurements of stack gas volumetric flow rate, diluent gas 7.2 Reporting Requirements. volumetric flow rate during unit operation concentration, electrical load, and moisture 7.2.1 General Reporting Provisions. The are required for routine operation of sorbent data, as applicable) are obtained for the hour; owner or operator shall comply with the trap monitoring systems, to maintain the 7.1.8.3 An identification code for the following requirements for reporting Hg required ratio of stack gas flow rate to sample formula (either the selected equation from emissions from each affected unit (or group flow rate (see section 8.2.2 of Performance Method 19 in section 6.2.1 of this appendix of units monitored at a common stack) under Specification (PS) 12B in Appendix B to part or Equation A–4 in section 6.2.2 of this this subpart: 60 of this chapter). Hourly stack gas flow rate appendix) used to derive the hourly Hg 7.2.1.1 Notifications, in accordance with data are also needed in order to demonstrate emission rate from Hg concentration, flow paragraph 7.2.2 of this section; compliance with electrical output-based Hg rate, electrical load, diluent gas 7.2.1.2 Monitoring plan reporting, in emissions limits, as provided in section 6.2.2 concentration, and moisture data (as accordance with paragraph 7.2.3 of this of this appendix. applicable); and section; 7.1.5.2 For each affected unit or common 7.1.8.4 A code indicating that the Hg 7.2.1.3 Certification, recertification, and stack, if hourly measurements of stack gas emission rate was not calculated for the hour, QA test submittals, in accordance with flow rate are needed for sorbent trap if valid data for Hg concentration and/or any paragraph 7.2.4 of this section; and monitoring system operation or to convert Hg of the other necessary parameters are not 7.2.1.4 Electronic quarterly report concentrations to the units of the emission obtained for the hour. For the purposes of submittals, in accordance with paragraph standard, use a flow rate monitor that meets this appendix, the substitute data values 7.2.5 of this section. the requirements of part 75 of this chapter to required under part 75 of this chapter for 7.2.2 Notifications. The owner or operator record the required data. You must keep diluent gas concentration, stack gas flow rate shall provide notifications for each affected hourly flow rate records, as specified in and moisture content are not considered to unit (or group of units monitored at a § 75.57(c)(2) of this chapter. be valid data. common stack) under this subpart in 7.1.6 Records of Stack Gas Moisture 7.1.9 Certification and Quality Assurance accordance with § 63.10030. Content. Test Records. For any Hg CEMS and sorbent 7.2.3 Monitoring Plan Reporting. For each 7.1.6.1 Correction of hourly Hg trap monitoring systems used to provide data affected unit (or group of units monitored at concentration data for moisture is sometimes under this subpart, record the following a common stack) under this subpart using Hg required when converting Hg concentrations certification and quality-assurance CEMS or sorbent trap monitoring system to to the units of the applicable Hg emissions information: measure Hg emissions, the owner or operator limit. In particular, these corrections are 7.1.9.1 The reference values, monitor shall make electronic and hard copy required: responses, and calculated calibration error monitoring plan submittals as follows: 7.1.6.1.1 For sorbent trap monitoring (CE) values, and a flag to indicate whether 7.2.3.1 Submit the electronic and hard systems; the test was done using elemental or oxidized copy information in section 7.1.1.2 of this 7.1.6.1.2 For Hg CEMS that measure Hg Hg, for all required 7-day calibration error appendix pertaining to the Hg monitoring concentration on a dry basis, when you must tests and daily calibration error tests of the systems at least 21 days prior to the calculate electrical output-based Hg emission Hg CEMS; applicable date in § 63.9984. Also submit the rates; and 7.1.9.2 The reference values, monitor monitoring plan information in § 75.53.(g) 7.1.6.1.3 When using certain equations responses, and calculated linearity error (LE) pertaining to the flow rate, diluent gas, and from EPA Method 19 in appendix A–7 to part or system integrity error (SIE) values for all moisture monitoring systems within that 60 of this chapter to calculate heat input- linearity checks of the Hg CEMS, and for all same time frame, if the required records are based Hg emission rates. single-level and 3-level system integrity not already in place. 7.1.6.2 If hourly moisture corrections are checks of the Hg CEMS; 7.2.3.2 Whenever an update of the required, either use a fuel-specific default 7.1.9.3 The CEMS and reference method monitoring plan is required, as provided in moisture percentage from § 75.11(b)(1) of this readings for each test run and the calculated paragraph 7.1.1.1 of this section. An chapter or a certified moisture monitoring relative accuracy results for all RATAs of the electronic monitoring plan information

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update must be submitted either prior to or of each electronic quarterly emissions 9.1 of Performance Specification 15, with the concurrent with the quarterly report for the monitoring report. The compliance exceptions listed in sections 3.1.2.1 and calendar quarter in which the update is certification shall include a statement by a 3.1.2.2 below. required. responsible official with that official’s name, 3.1.1.1 The audit sample gas does not 7.2.3.3 All electronic monitoring plan title, and signature, certifying that, to the best have to be obtained from the Administrator; submittals and updates shall be made to the of his or her knowledge, the report is true, however, it must be (1) from a secondary Administrator using the ECMPS Client Tool. accurate, and complete. source of certified gases (i.e., independent of Hard copy portions of the monitoring plan any calibration gas used for the daily shall be kept on record according to section Appendix B to Subpart UUUUU—-HCl calibration assessments) and (2) directly 7.1 of this appendix. and HF Monitoring Provisions 7.2.4 Certification, Recertification, and traceable to National Institute of Standards 1. Applicability Quality-Assurance Test Reporting. Except for and Technology (NIST) or VSL Dutch daily QA tests of the required monitoring These monitoring provisions apply to the Metrology Institute (VSL) reference materials systems (i.e., calibration error tests and flow measurement of HCl and/or HF emissions through an unbroken chain of comparisons. monitor interference checks), the results of from electric utility steam generating units, If audit gas traceable to NIST or VSL all required certification, recertification, and using CEMS. The CEMS must be capable of reference materials is not available, you may quality-assurance tests described in measuring HCl and/or HF in the appropriate use a gas with a concentration certified to a paragraphs 7.1.10.1 through 7.1.10.7 of this units of the applicable emissions standard specified uncertainty by the gas section (except for test results previously (e.g., lb/MMBtu, lb/MWh, or lb/GWh). manufacturer. submitted, e.g., under the ARP) shall be 2. Monitoring of HCl and/or HF Emissions 3.1.1.2 Analyze the results of the gas submitted electronically, using the ECMPS audit using the calculations in section 12.1 Client Tool, either prior to or concurrent with 2.1 Monitoring System Installation of Performance Specification 15. The the relevant quarterly electronic emissions Requirements. Install HCl and/or HF CEMS calculated correction factor (CF) from Eq. 6 and any additional monitoring systems report. of Performance Specification 15 must be needed to convert pollutant concentrations to 7.2.5 Quarterly Reports. between 0.85 and 1.15. You do not have to units of the applicable emissions limit in 7.2.5.1 Beginning with the report for the test the bias for statistical significance. calendar quarter in which the initial accordance with Performance Specification 3.1.2 You must perform a relative compliance demonstration is completed or 15 for extractive Fourier Transform Infrared accuracy test audit or RATA according to the calendar quarter containing the Spectroscopy (FTIR) continuous emissions applicable date in § 63.9984, the owner or monitoring systems in appendix B to part 60 section 11.1.1.4 of Performance Specification operator of any affected unit shall use the of this chapter and § 63.10010(a). 15 and the requirements below. Perform the ECMPS Client Tool to submit electronic 2.2 Primary and Backup Monitoring RATA of the HCl or HF CEMS at normal quarterly reports to the Administrator, in an Systems. The provisions pertaining to load. Acceptable HCl/HF reference methods XML format specified by the Administrator, primary and redundant backup monitoring (RM) are Methods 26 and 26A in appendix for each affected unit (or group of units systems in section 2.2 of appendix A to this A–8 to part 60 of this chapter, Method 320 monitored at a common stack) under this subpart apply to HCl and HF CEMS and any in Appendix A to this part, or ASTM D6348– subpart. additional monitoring systems needed to 03 (Reapproved 2010) ‘‘Standard Test 7.2.5.2 The electronic reports must be convert pollutant concentrations to units of Method for Determination of Gaseous submitted within 30 days following the end the applicable emissions limit. Compounds by Extractive Direct Interface of each calendar quarter, except for units that 2.3 FTIR Monitoring System Equipment, Fourier Transform Infrared (FTIR) have been placed in long-term cold storage. Supplies, Definitions, and General Spectroscopy’’ (incorporated by reference, 7.2.5.3 Each electronic quarterly report Operation. The provisions of Performance see § 63.14), each applied based on the shall include the following information: Specification 15 Sections 2.0, 3.0, 4.0, 5.0, criteria set forth in Table 5 of this subpart. 7.2.5.3.1 The date of report generation; 6.0, and 10.0 apply. 3.1.2.1 When ASTM D6348–03 is used as 7.2.5.3.2 Facility identification 3. Initial Certification Procedures the RM, the following conditions must be information; met: The initial certification procedures for the 7.2.5.3.3 The information in paragraphs 3.1.2.1.1 The test plan preparation and HCl or HF CEMS used to provide data under 7.1.2 through 7.1.8 of this section, as implementation in the Annexes to ASTM this subpart are as follows: applicable to the Hg emission measurement D6348–03, Sections A1 through A8 are methodology (or methodologies) used and 3.1 The HCl and/or HF CEMS must be mandatory; the units of the Hg emission standard(s); and certified according to Performance 3.1.2.1.2 In ASTM D6348–03 Annex A5 7.2.5.3.4 The results of all daily Specification 15 using the procedures for gas calibration error tests of the Hg CEMS, as auditing and comparison to a reference (Analyte Spiking Technique), the percent (%) described in paragraph 7.1.90.1 of this method (RM) as specified in sections 3.1.1 R must be determined for each target analyte section and (if applicable) the results of all and 3.1.2 below. (Please Note: EPA plans to (see Equation A5.5); daily flow monitor interference checks. publish a technology neutral performance 3.1.2.1.3 For the ASTM D6348–03 test 7.2.5.4 Compliance Certification. Based specification and appropriate on-going data to be acceptable for a target analyte, %R on reasonable inquiry of those persons with quality-assurance requirements for HCl must be 70% ≥ R ≤ 130%; and primary responsibility for ensuring that all CEMS in the near future along with 3.1.2.1.4 The %R value for each Hg emissions from the affected unit(s) under amendments to this appendix to compound must be reported in the test report this subpart have been correctly and fully accommodate their use.) and all field measurements corrected with monitored, the owner or operator shall 3.1.1 You must conduct a gas audit of the the calculated %R value for that compound submit a compliance certification in support HCl and/or HF CEMS as described in section using the following equation:

3.1.2.2 The relative accuracy (RA) of the if the absolute value of the difference concentrations in units of the applicable HCl or HF CEMS must be no greater than 20 between the mean RM and CEMS values does emissions limit must be certified according to percent of the mean value of the RM test data not exceed 0.20 ppm. part 75 of this chapter. in units of ppm on the same moisture basis. 3.2 Any additional stack gas flow rate, Alternatively, if the mean RM value is less diluent gas, and moisture monitoring than 1.0 ppm, the RA results are acceptable system(s) needed to express pollutant

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4. Recertification Procedures 5.1.3 You must perform an annual calendar quarter in which the grace period Whenever the owner or operator makes a relative accuracy test audit or RATA of the audit is performed is a QA operating quarter, replacement, modification, or change to a HCl or HF CEMS as described in section 3.1.2 an additional gas audit is required for that certified CEMS that may significantly affect of this appendix. Perform the RATA at quarter. the ability of the system to accurately normal load. For the purposes of this 5.3.2.3.3 For the RATA of a HCl or HF measure or record pollutant or diluent gas appendix, ‘‘annual’’ means once every four CEMS, the next RATA is due within three concentrations, stack gas flow rates, or stack ‘‘QA operating quarters’’ (as defined in QA operating quarters after the calendar gas moisture content, the owner or operator section 3.1.20 of appendix A to this subpart). quarter in which the grace period test is shall recertify the monitoring system. The first annual RATA is due within four QA performed. Furthermore, whenever the owner or operating quarters following the calendar 5.3.4 Conditional Data Validation. For operator makes a replacement, modification, quarter in which the initial certification recertification and diagnostic testing of the or change to the flue gas handling system or testing of the HCl or HF CEMS is successfully monitoring systems that are used to provide the unit operation that may significantly completed. The provisions in section 5.1.2.4 data under this appendix, and for the change the concentration or flow profile, the of appendix A to this subpart pertaining to required QA tests when non-redundant owner or operator shall recertify the RATA deadline extensions also apply. backup monitoring systems or temporary monitoring system. The same tests performed 5.2 Stack gas flow rate, diluent gas, and like-kind replacement analyzers are brought for the initial certification of the monitoring moisture monitoring systems must meet the into service, the conditional data validation system shall be repeated for recertification, applicable on-going QA test requirements of provisions in §§ 75.20(b)(3)(ii) through unless otherwise specified by the part 75 of this chapter. (b)(3)(ix) of this chapter may be used to avoid Administrator. Examples of changes that 5.3 Data Validation. or minimize data loss. The allotted window require recertification include: Replacement 5.3.1 Out-of-Control Periods. A HCl or HF of time to complete calibration tests and of a gas analyzer; complete monitoring CEMS that is used to provide data under this RATAs shall be as specified in system replacement, and changing the appendix is considered to be out-of-control, § 75.20(b)(3)(iv) of this chapter; the allotted location or orientation of the sampling probe. and data from the CEMS may not be reported window of time to complete a gas audit shall as quality-assured, when any acceptance be the same as for a linearity check (i.e., 168 5. On-Going Quality Assurance criteria for a required QA test is not met. The unit or stack operating hours). Requirements HCl or HF CEMS is also considered to be out- 6. Missing Data Requirements 5.1 For on-going QA test requirements for of-control when a required QA test is not For the purposes of this appendix, the HCl and HF CEMS, implement the quality performed on schedule or within an allotted owner or operator of an affected unit shall assurance/quality control procedures of grace period. To end an out-of-control period, not substitute for missing data from HCl or Performance Specification 15 of appendix B the QA test that was either failed or not done HF CEMS. Any process operating hour for to part 60 of this chapter as set forth in on time must be performed and passed. Out- which quality-assured HCl or HF sections 5.1.1 through 5.1.3 and 5.3.2 of this of-control periods are counted as hours of concentration data are not obtained is appendix. monitoring system downtime. counted as an hour of monitoring system 5.1.1 On a daily basis, you must assess 5.3.2 Grace Periods. For the purposes of downtime. the calibration error of the HCl or HF CEMS this appendix, a ‘‘grace period’’ is defined as using either a calibration transfer standard as a specified number of unit or stack operating 7. Bias Adjustment hours after the deadline for a required specified in Performance Specification 15 Bias adjustment of hourly emissions data quality-assurance test of a continuous Section 10.1 which references Section 4.5 of from a HCl or HF CEMS is not required. the FTIR Protocol or a HCl and/or HF monitor has passed, in which the test may be calibration gas at a concentration no greater performed and passed without loss of data. 8. QA/QC Program Requirements than two times the level corresponding to the 5.3.2.1 For the flow rate, diluent gas, and The owner or operator shall develop and applicable emission limit. A calibration moisture monitoring systems described in implement a quality assurance/quality transfer standard is a substitute calibration section 5.2 of this appendix, a 168 unit or control (QA/QC) program for the HCl and/or compound chosen to ensure that the FTIR is stack operating hour grace period is available HF CEMS that are used to provide data under performing well at the wavelength regions for quarterly linearity checks, and a 720 unit this subpart. At a minimum, the program used for analysis of the target analytes. The or stack operating hour grace period is shall include a written plan that describes in measured concentration of the calibration available for RATAs, as provided, detail (or that refers to separate documents transfer standard or HCl and/or HF respectively, in sections 2.2.4 and 2.3.3 of containing) complete, step-by-step ± calibration gas results must agree within 5 appendix B to part 75 of this chapter. procedures and operations for the most percent of the reference gas value after 5.3.2.2 For the purposes of this appendix, important QA/QC activities. Electronic correction for differences in pressure. if the deadline for a required gas audit or storage of the QA/QC plan is permissible, 5.1.2 On a quarterly basis, you must RATA of a HCl or HF CEMS cannot be met provided that the information can be made conduct a gas audit of the HCl and/or HF due to circumstances beyond the control of available in hard copy to auditors and CEMS as described in section 3.1.1 of this the owner or operator: inspectors. The QA/QC program appendix. For the purposes of this appendix, 5.3.2.2.1 A 168 unit or stack operating requirements for the other monitoring ‘‘quarterly’’ means once every ‘‘QA operating hour grace period is available in which to systems described in section 5.2 of this quarter’’ (as defined in section 3.1.20 of perform the gas audit; or appendix are specified in section 1 of appendix A to this subpart). You have the 5.3.2.2.2 A 720 unit or stack operating appendix B to part 75 of this chapter. option to use HCl gas in lieu of HF gas for hour grace period is available in which to 8.1 General Requirements for HCl and HF conducting this audit on an HF CEMS. To the perform the RATA. CEMS. extent practicable, perform consecutive 5.3.2.3 If a required QA test is performed 8.1.1 Preventive Maintenance. Keep a quarterly gas audits at least 30 days apart. during a grace period, the deadline for the written record of procedures needed to The initial quarterly audit is due in the first next test shall be determined as follows: maintain the HCl and/or HF CEMS in proper QA operating quarter following the calendar 5.3.2.3.1 For a gas audit or RATA of the operating condition and a schedule for those quarter in which certification testing of the monitoring systems described in section 5.1 procedures. This shall, at a minimum, CEMS is successfully completed. Up to three of this appendix, determine the deadline for include procedures specified by the consecutive exemptions from the quarterly the next gas audit or RATA (as applicable) in manufacturers of the equipment and, if audit requirement are allowed for ‘‘non-QA accordance with section 2.2.4(b) or 2.3.3(d) of applicable, additional or alternate procedures operating quarters’’ (i.e., calendar quarters in appendix B to part 75 of this chapter; treat developed for the equipment. which there are less than 168 unit or stack a gas audit in the same manner as a linearity 8.1.2 Recordkeeping and Reporting. Keep operating hours). However, no more than check. a written record describing procedures that four consecutive calendar quarters may 5.3.2.3.2 For the gas audit of a HCl or HF will be used to implement the recordkeeping elapse without performing a gas audit, except CEMS, the grace period test only satisfies the and reporting requirements of this appendix. as otherwise provided in section 5.3.3.2.1 of audit requirement for the calendar quarter in 8.1.3 Maintenance Records. Keep a this appendix. which the test was originally due. If the record of all testing, maintenance, or repair

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activities performed on any HCl or HF CEMS 10. Recordkeeping Requirements common stack, to the extent that these data in a location and format suitable for 10.1 For each HCl or HF CEMS installed are needed to convert pollutant concentration inspection. A maintenance log may be used at an affected source, and for any other data to the units of the emission standard. for this purpose. The following records monitoring system(s) needed to convert For non-operating hours, record only the should be maintained: Date, time, and pollutant concentrations to units of the items in paragraphs 10.1.2.1 and 10.1.2.2 of description of any testing, adjustment, repair, applicable emissions limit, the owner or this section. If there is heat input to the replacement, or preventive maintenance operator must maintain a file of all unit(s), but no electrical load, record only the action performed on any monitoring system measurements, data, reports, and other items in paragraphs 10.1.2.1, 10.1.2.2, and (if and records of any corrective actions information required by this appendix in a applicable) 10.1.2.4 of this section. associated with a monitor outage period. form suitable for inspection, for 5 years from 10.1.2.1 The date and hour; 10.1.2.2 The unit or stack operating time Additionally, any adjustment that may the date of each record, in accordance with (rounded up to the nearest fraction of an hour significantly affect a system’s ability to § 63.10033. The file shall contain the information in paragraphs 10.1.1 through (in equal increments that can range from one accurately measure emissions data must be hundredth to one quarter of an hour, at the recorded and a written explanation of the 10.1.8 of this section. 10.1.1 Monitoring Plan Records. For each option of the owner or operator); procedures used to make the adjustment(s) 10.1.2.3 The hourly gross unit load shall be kept. affected unit or group of units monitored at a common stack, the owner or operator shall (rounded to nearest MWge); and 8.2 Specific Requirements for HCl and HF 10.1.2.4 If applicable, the F-factor used to CEMS. The following requirements are prepare and maintain a monitoring plan for the HCl and/or HF CEMS and any other calculate the heat input-based pollutant specific to HCl and HF CEMS: monitoring system(s) (i.e, flow rate, diluent emission rate. 8.2.1 Keep a written record of the gas, or moisture systems) needed to convert 10.1.3 HCl and/or HF Emissions Records. procedures used for each type of QA test pollutant concentrations to units of the For HCl and/or HF CEMS, the owner or required for each HCl and HF CEMS. Explain applicable emission standard. The operator must record the following how the results of each type of QA test are monitoring plan shall contain essential information for each unit or stack operating calculated and evaluated. information on the continuous monitoring hour: 8.2.2 Explain how each component of the systems and shall explain how the data 10.1.3.1 The date and hour; HCl and/or HF CEMS will be adjusted to derived from these systems ensure that all 10.1.3.2 Monitoring system and provide correct responses to calibration gases HCl or HF emissions from the unit or stack component identification codes, as provided after routine maintenance, repairs, or are monitored and reported. in the electronic monitoring plan, for each corrective actions. 10.1.1.1 Updates. Whenever the owner or hour in which the CEMS provides a quality- operator makes a replacement, modification, assured value of HCl or HF concentration (as 9. Data Reduction and Calculations or change in a certified continuous HCl or HF applicable); 9.1 Design and operate the HCl and/or HF monitoring system that is used to provide 10.1.3.3 The pollutant concentration, for CEMS to complete a minimum of one cycle data under this subpart (including a change each hour in which a quality-assured value of operation (sampling, analyzing, and data in the automated data acquisition and is obtained. For HCl and HF, record the data recording) for each successive 15-minute handling system or the flue gas handling in parts per million (ppm), rounded to three period. system) which affects information reported in significant figures. 9.2 Reduce the HCl and/or HF the monitoring plan (e.g., a change to a serial 10.1.3.4 A special code, indicating concentration data to hourly averages in number for a component of a monitoring whether or not a quality-assured HCl or HF accordance with § 60.13(h)(2) of this chapter. system), the owner or operator shall update concentration value is obtained for the hour. 9.3 Convert each hourly average HCl or the monitoring plan. This code may be entered manually when a HF concentration to an HCl or HF emission 10.1.1.2 Contents of the Monitoring Plan. temporary like-kind replacement HCl or HF rate expressed in units of the applicable For HCl and/or HF CEMS, the monitoring analyzer is used for reporting; and emissions limit. plan shall contain the applicable electronic 10.1.3.5 Monitor data availability, as a 9.3.1 For heat input-based emission rates, and hard copy information in sections percentage of unit or stack operating hours, select an appropriate emission rate equation 10.1.1.2.1 and 10.1.1.2.2 of this appendix. calculated according to § 75.32 of this from among Equations 19–1 through 19–9 in For stack gas flow rate, diluent gas, and chapter. EPA Method 19 in appendix A–7 to part 60 moisture monitoring systems, the monitoring 10.1.4 Stack Gas Volumetric Flow Rate Records. of this chapter, to calculate the HCl or HF plan shall include the electronic and hard copy information required for those systems 10.1.4.1 Hourly measurements of stack emission rate in lb/MMBtu. Multiply the HCl ¥ under § 75.53 (g) of this chapter. The gas volumetric flow rate during unit concentration value (ppm) by 9.43 × 10 8 to electronic monitoring plan shall be evaluated operation are required to demonstrate convert it to lb/scf, for use in the applicable using the ECMPS Client Tool. compliance with electrical output-based HCl Method 19 equation. For HF, the conversion 10.1.1.2.1 Electronic. Record the unit or or HF emissions limits (i.e., lb/MWh or lb/ constant from ppm to lb/scf is 5.18 × 10¥8. stack ID number(s); monitoring location(s); GWh). 9.3.2 For electrical output-based emission the HCl or HF monitoring methodology used 10.1.4.2 Use a flow rate monitor that rates, first calculate the HCl or HF mass (i.e., CEMS); HCl or HF monitoring system meets the requirements of part 75 of this emission rate (lb/h), using an equation that information, including, but not limited to: chapter to record the required data. You must has the general form of Equation A–2 or A– unique system and component ID numbers; keep hourly flow rate records, as specified in 3 in appendix A to this subpart (as the make, model, and serial number of the § 75.57(c)(2) of this chapter. applicable), replacing the value of K with monitoring equipment; the sample 10.1.5 Records of Stack Gas Moisture × ¥8 × 9.43 10 lb/scf-ppm (for HCl) or 5.18 acquisition method; formulas used to Content. ¥8 10 (for HF) and defining Ch as the hourly calculate emissions; monitor span and range 10.1.5.1 Correction of hourly pollutant average HCl or HF concentration in ppm. information (if applicable). concentration data for moisture is sometimes Then, use Equation A–4 in appendix A to 10.1.1.2.2 Hard Copy. Keep records of the required when converting concentrations to this subpart to calculate the HCl or HF following: schematics and/or blueprints the units of the applicable Hg emissions emission rate in lb/GWh. If the applicable showing the location of the monitoring limit. In particular, these corrections are HCl or HF limit is expressed in lb/MWh, system(s) and test ports; data flow diagrams; required: divide the result from Equation A–4 by 103. test protocols; monitor span and range 10.1.5.1.1 To calculate electrical output- 9.4 Use Equation A–5 in appendix A of calculations (if applicable); miscellaneous based pollutant emission rates, when using a this subpart to calculate the required 30 technical justifications. CEMS that measures pollutant concentrations operating day rolling average HCl or HF 10.1.2 Operating Parameter Records. For on a dry basis; and emission rates. Round off each 30 operating the purposes of this appendix, the owner or 10.1.5.1.2 To calculate heat input-based day average to two significant figures. The operator shall record the following pollutant emission rates, when using certain term Eho in Equation A–5 must be in the units information for each operating hour of each equations from EPA Method 19 in appendix of the applicable emissions limit. affected unit or group of units utilizing a A–7 to part 60 of this chapter.

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10.1.5.2 If hourly moisture corrections are 10.1.8.1.2 For gas audits of HCl or HF 11.4 Certification, Recertification, and required, either use a fuel-specific default CEMS, record the date and time of each Quality-Assurance Test Reporting moisture percentage for coal-fired units from spiked and unspiked sample, the audit gas Requirements. Except for daily QA tests (i.e., § 75.11(b)(1) of this chapter, an Administrator reference values and uncertainties. Keep calibrations and flow monitor interference approved default moisture value for non- records of all calculations and data analyses checks), which are included in each coal-fired units (as per paragraph 63.10010(d) required under sections 9.1 and 12.1 of electronic quarterly emissions report, use the of this subpart), or a certified moisture Performance Specification 15, and the results ECMPS Client Tool to submit the results of monitoring system that meets the of those calculations and analyses. all required certification, recertification, requirements of part 75 of this chapter, to 10.1.8.1.3 For each RATA of a HCl or HF quality-assurance, and diagnostic tests of the record the required data. If you elect to use CEMS, record the date and time of each test monitoring systems required under this a moisture monitoring system, you must keep run, the reference method(s) used, and the appendix electronically, either prior to or hourly records of the stack gas moisture reference method and HCl or HF CEMS concurrent with the relevant quarterly content, as specified in § 75.57(c)(3) of this values. Keep records of the data analyses and electronic emissions report. chapter. calculations used to determine the relative 11.4.1 For daily calibrations (including 10.1.6 Records of Diluent Gas (CO2 or O2) accuracy. calibration transfer standard tests), report the Concentration. 10.1.8.2 Additional Monitoring Systems. information in § 75.59(a)(1) of this chapter, 10.1.6.1 To assess compliance with a heat For the stack gas flow rate, diluent gas, and excluding paragraphs (a)(1)(ix) through input-based HCl or HF emission rate limit in moisture monitoring systems described in (a)(1)(xi). units of lb/MMBtu, hourly measurements of section 3.2 of this appendix, you must keep 11.4.2 For each quarterly gas audit of a CO2 or O2 concentration are required to records of all certification, recertification, HCl or HF CEMS, report: convert pollutant concentrations to units of diagnostic, and on-going quality-assurance 11.4.2.1 Facility ID information; the standard. tests of these systems, as specified in 11.4.2.2 Monitoring system ID number; 10.1.6.2 If hourly measurements of § 75.59(a) of this chapter. 11.4.2.3 Type of test (e.g., quarterly gas diluent gas concentration are needed, you audit); 11. Reporting Requirements must use a certified CO2 or O2 monitor that 11.4.2.4 Reason for test; meets the requirements of part 75 of this 11.1 General Reporting Provisions. The 11.4.2.5 Certified audit (spike) gas chapter to record the required data. For all owner or operator shall comply with the concentration value (ppm); diluent gas monitors, you must keep hourly following requirements for reporting HCl 11.4.2.6 Measured value of audit (spike) CO2 or O2 concentration records, as specified and/or HF emissions from each affected unit gas, including date and time of injection; in § 75.57(g) of this chapter. (or group of units monitored at a common 11.4.2.7 Calculated dilution ratio for 10.1.7 HCl and HF Emission Rate stack): audit (spike) gas; Records. For applicable HCl and HF emission 11.1.1 Notifications, in accordance with 11.4.2.8 Date and time of each spiked flue limits in units of lb/MMBtu, lb/MWh, or lb/ paragraph 11.2 of this section; gas sample; GWh, record the following information for 11.1.2 Monitoring plan reporting, in 11.4.2.9 Date and time of each unspiked each affected unit or common stack: accordance with paragraph 11.3 of this flue gas sample; 10.1.7.1 The date and hour; section; 11.4.2.10 The measured values for each 10.1.7.2 The hourly HCl and/or HF 11.1.3 Certification, recertification, and spiked gas and unspiked flue gas sample emissions rate (lb/MMBtu, lb/MWh, or lb/ QA test submittals, in accordance with (ppm); GWh, as applicable, rounded to three paragraph 11.4 of this section; and 11.4.2.11 The mean values of the spiked significant figures), for each hour in which 11.1.4 Electronic quarterly report and unspiked sample concentrations and the valid values of HCl or HF concentration and submittals, in accordance with paragraph expected value of the spiked concentration as all other required parameters (stack gas 11.5 of this section. specified in section 12.1 of Performance volumetric flow rate, diluent gas 11.2 Notifications. The owner or operator Specification 15 (ppm); concentration, electrical load, and moisture shall provide notifications for each affected 11.4.2.12 Bias at the spike level as data, as applicable) are obtained for the hour; unit (or group of units monitored at a calculated using equation 3 in section 12.1 of 10.1.7.3 An identification code for the common stack) in accordance with Performance Specification 15; and formula used to derive the hourly HCl or HF § 63.10030. 11.4.2.13 The correction factor (CF), emission rate from HCl or HF concentration, 11.3 Monitoring Plan Reporting. For each calculated using equation 6 in section 12.1 of flow rate, electrical load, diluent gas affected unit (or group of units monitored at Performance Specification 15. concentration, and moisture data (as a common stack) using HCl and/or HF CEMS, 11.4.3 For each RATA of a HCl or HF applicable); and the owner or operator shall make electronic CEMS, report: 10.1.7.4 A code indicating that the HCl or and hard copy monitoring plan submittals as 11.4.3.1 Facility ID information; HF emission rate was not calculated for the follows: 11.4.3.2 Monitoring system ID number; hour, if valid data for HCl or HF 11.3.1 Submit the electronic and hard 11.4.3.3 Type of test (i.e., initial or annual concentration and/or any of the other copy information in section 10.1.1.2 of this RATA); necessary parameters are not obtained for the appendix pertaining to the HCl and/or HF 11.4.3.4 Reason for test; hour. For the purposes of this appendix, the monitoring systems at least 21 days prior to 11.4.3.5 The reference method used; substitute data values required under part 75 the applicable date in § 63.9984. Also, if 11.4.3.6 Starting and ending date and of this chapter for diluent gas concentration, applicable, submit monitoring plan time for each test run; stack gas flow rate and moisture content are information pertaining to any required flow 11.4.3.7 Units of measure; not considered to be valid data. rate, diluent gas, and/or moisture monitoring 11.4.3.8 The measured reference method 10.1.8 Certification and Quality systems within that same time frame, if the and CEMS values for each test run, on a Assurance Test Records. For the HCl and/or required records are not already in place. consistent moisture basis, in appropriate HF CEMS used to provide data under this 11.3.2 Update the monitoring plan when units of measure; subpart at each affected unit (or group of required, as provided in paragraph 10.1.1.1 of 11.4.3.9 Flags to indicate which test runs units monitored at a common stack), record this appendix. An electronic monitoring plan were used in the calculations; the following information for all required information update must be submitted either 11.4.3.10 Arithmetic mean of the CEMS certification, recertification, diagnostic, and prior to or concurrent with the quarterly values, of the reference method values, and quality-assurance tests: report for the calendar quarter in which the of their differences; 10.1.8.1 HCl and HF CEMS. update is required. 11.4.3.11 Standard deviation, as specified 10.1.8.1.1 For all required daily 11.3.3 All electronic monitoring plan in Equation 2–4 of Performance Specification calibrations (including calibration transfer submittals and updates shall be made to the 2 in appendix B to part 60 of this chapter; standard tests) of the HCl or HF CEMS, Administrator using the ECMPS Client Tool. 11.4.3.12 Confidence coefficient, as record the test dates and times, reference Hard copy portions of the monitoring plan specified in Equation 2–5 of Performance values, monitor responses, and calculated shall be kept on record according to section Specification 2 in appendix B to part 60 of calibration error values; 10.1 of this appendix. this chapter; and

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11.4.3.13 Relative accuracy calculated (whichever is earlier), the owner or operator standard tests) of the HCl or HF monitor as using Equation 2–6 of Performance of any affected unit shall use the ECMPS described in section 10.1.8.1.1 of this Specification 2 in appendix B to part 60 of Client Tool to submit electronic quarterly appendix; and this chapter or, if applicable, according to the reports to the Administrator, in an XML 11.5.3.5 If applicable, the results of all alternative procedure for low emitters format specified by the Administrator, for daily flow monitor interference checks, in described in section 3.1.2.2 of this appendix. each affected unit (or group of units accordance with section 10.1.8.2 of this If applicable use a flag to indicate that the monitored at a common stack). appendix. alternative RA specification for low emitters 11.5.2 The electronic reports must be 11.5.4 Compliance Certification. Based has been applied. submitted within 30 days following the end on reasonable inquiry of those persons with 11.4.4 Reporting Requirements for of each calendar quarter, except for units that primary responsibility for ensuring that all Diluent Gas, Flow Rate, and Moisture have been placed in long-term cold storage. HCl and/or HF emissions from the affected Monitoring Systems. For the certification, 11.5.3 Each electronic quarterly report unit(s) have been correctly and fully recertification, diagnostic, and QA tests of shall include the following information: monitored, the owner or operator shall stack gas flow rate, moisture, and diluent gas 11.5.3.1 The date of report generation; submit a compliance certification in support monitoring systems that are certified and 11.5.3.2 Facility identification of each electronic quarterly emissions quality-assured according to part 75 of this information; monitoring report. The compliance chapter, report the information in section 11.5.3.3 The information in sections certification shall include a statement by a 10.1.9.3 of this appendix. 10.1.2 through 10.1.7 of this appendix, as responsible official with that official’s name, 11.5 Quarterly Reports. applicable to the type(s) of monitoring title, and signature, certifying that, to the best 11.5.1 Beginning with the report for the system(s) used to measure the pollutant of his or her knowledge, the report is true, calendar quarter in which the initial concentrations and other necessary accurate, and complete. compliance demonstration is completed or parameters. the calendar quarter containing the 11.5.3.4 The results of all daily [FR Doc. 2012–806 Filed 2–15–12; 8:45 am] applicable date in § 63.10005(g), (h), or (j) calibrations (including calibration transfer BILLING CODE 6560–50–P

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