# Joint Appendix — Nat'l Mining Ass'n v. Envtl. Prot. Agency, 135 S. Ct. 703 (2014) (No. 14-49) > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385016_0333%3A09 ## Record - **Collection:** Supreme Court brief - **Document type:** Joint Appendix - **Published:** January 1, 2014 ## Text Sup = et US AND JAN 23 206 CRIEFS Nos. 14-46, 14-47, 14-49 OFFICE OF TH' CLERK Bu the Supreme Court of the United States 62] — MICHIGAN, ET AL., PETTTIONERS Vv. ENVIRONMENTAL PROTECTION AGENCY, ET AL. Utuiry Am REGULATORY GROUP, PETITIONER Vv. ENVIRONMENTAL PROTECTION AGENCY, ET AL. NATIONAL MINING ASSOCIATION, PETITIONER Vv. ENVIRONMENTAL PROTECTION AGENCY, ET AL. On Waits OF CERTIORARI TO THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT \ JOINT APPENDIX - VOLUME 1 OF 4 Donald B. Verrilli, Jr. Aaron D. Lindstrom Counsel of Record oi of Record Department of Justice O. Box 30212 Washington, DC. Lansing, = Pacey —_— (517) 373-1124 SupremeCtBniefs@usdo}j.gov (202) 514-2217 Petitions for Writ of Certiorari Filed July 14, 2014 Writs of Certiorari Granted November 25, 2014 Library of Congress Law Library Melissa Hoffer Counsel of Record Assistant Attorney General Environmental Protection One Ashburton Place 18th Floor Boston, MA 02130 melissa. hoffer@ state.ma.us (617) 963-2322 Brendan K. Collins Counsel of Record Ballard Spahr LLP 1735 Market Street 51st Floor Philadelphia, PA 19103 collins@ballardspahr.com (215) 665-8500 Sean H. Donahue Counsel of Record Donahue & Goldberg LLP 1130 Connecticut Ave., NW Suite 950 Washington, D.C. 20036 sean@donahuegoldberg.com (202) 277-7085 F. William Brownell Counsel of Record Hunton & Williams LLP 2200 Pennsylvania Ave., NW Washington, D.C. 20037 bbrownell@hunton.com (202) 955-1500 Peter S. Glaser Counsel of Record Troutman Sanders LLP 401 Ninth Street, NW Suite 1000 Washington, D.C. 20004 Peter.glaser@ troutmansanders.com (202) 274-2998 TABLE OF CONTENTS VOLUME 1 OF 4 Relevant Docket Entries White Stallion Energy Center v. EPA Court of Appeals Docket No. 12-1100 1-26 ee ee ee U.S. EPA, Mercury Study Report to Congress, Vol. 1: Executive Summary, EPA-452/R-97-003 Docket No. EPA-HQ-OAR-2009-0234-3054 December 1997 Excerpts Overview [pp. O-1 to O-4] 27-35 Report to Congress [pp. 1-1 to 1-3] 36-43 ee [pp. 4-1 to 4-10] 4460 Tee eee ee ee EPA Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units — Final Report to Congress, Volume 1- Docket No. EPA-HQ-OAR-2009-0234-3052 February 1998 Excerpts Executive Summary [pp. ES-1 to ES-29] Utility Study Section 2.7 [p. 2-25] Title I and Title IV, Phase I and Phase IJ, Compliance Strategy Impact ee ro) 117-119 6.0 Inhalation Risk Assessment SSS Lepper Bante rec ee Bete SS 120-131 ee en ee ee Ceo 132—134 Areas for Further Research and Analysis a en roe 3 ab ee 135-138 69 Fed. Reg. 4652 January 30, 2004 [pp. 4657 to 4659] 139-145 70 Fed. Reg. 15994 March 29, 2005 Sections F & G a ee NO 146-162 Coal-to-Gas Conversion TSD, EPA-HQ-OAR-2009-0234-3065 March 4, 2011 163—166 Memo, “National Emission Standards for Hazardous Air Pollutants (NESHAP) Beyond the Maximum Achievable Control Technology (MACT) Floor Analysis for Coal- and Oil-fired Electric Utility Steam Generating EGUs” EPA-HQ-OAR-2009-0234-2924 March 14, 2011 167-179 eee ete eee eee ee eee eT eee ee Te eee ee eee ee National Mining Association’s Comments Docket No. EPA-HQ-2009-0234 (NESHAP action) and EPA-HQ-OAR-2011-0044 (NSPS) 76 Federal Register 24,976 May 3, 2011 ON |): eae Ps Sa 180-185 Connecticut Department of Energy and Environmental Protection comments EPA-HQ-OAR-2009-0234-20298 July 12, 2011 Excerpts Cover letter and attachment Pata a se ON oo eS Re 186—193 South Carolina Department of Health and Environmental Control comments EPA-HQ-OAR-2011-0444-5749 er 194—213 iv Massachusetts Department of Environmental Protection comments EPA-HQ-OAR-2009-0234-18039 July 29, 2011 [pp. 1 to 4] 214-218 [pp. 6 to 7] 219-227 Oe ES SOE EES ES EEE EEE SHEESH OH TOSS SS OOH O OS New England Interstate Water Pollution Control Commission comments EPA-HQ-OAR-2009-0234-17625 August 2, 2011 228-231 Northeast States for Coordinated Air Use Management comments EPA-HQ-OAR-2009-0234-17843 August 2, 2011 Excerpts 232-252 pe eel Attachment A (table) [pp. A-1 to A-2] 253-254 VOLUME 2 OF 4 Michigan Department of Environmental Quaiity comments, EPA-HQ-0234-2009-0234-18426 ee el 255-277 National Association of Clean Air Agencies comments, EPA-HQOAR-2009-0234-17620 August 4, 2011 Excerpts Cover letter and comments ge ial ect oat ose enna 278~—305 306—320 New Jersey Department of Environmental Protection, comments EPAHQ-OAR-2009-0234-18444 August 4, 2011 CRUVER NES eee Oran Bee Lh iOS aed) aoe 321-323 OSS a ae 324-327 Comments of Environmental and Public Health Groups on the National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units; Proposed Rule. Docket No. EPA-HQ-OAR-2011-0044-5715 August 4, 2011 Excerpt Chapter I [pp. I-1 to I-38] 330-382 Comments of Environmental Defense Fund on the National Emission Standards for Hazardous Air Pollutants From Coal-and Oil-Fired Electric Utility Steam Generating Units, Docket No. EPA-HQ-OAR- 2009-0234-18421 August 4, 2011 Excerpt Part I [pp. 3 to 7] 383—392 EPRI Comments on Proposed HAPs MACT Rule EPA-HQ-2009-0234-17621 August 4, 2011 Excerpts Specific Comments on the Environmental Fate and Transport, Exposure and Human Health Issues, and Risk Analyses [p. vilitox] ss EPRI’s comprehensive sector-wide inhalation risk assessment on all 470 coal-fired generating facilities identified no cancer or non-cancer health risks above regulatory risk threshold, in contrast to EPA’s 16 case studies assessment ke ee ree. 399-411 a SS eee eee 412-418 a ee 419-422 Exelon Corporation, Comments on the National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units; Proposed Rule, Docket No. EPA- HQ-OAR-2009-0234-17648, Part 1 of 3 August 4, 2011 Excerpts Comment 1, Sections 1.1 through 1.2 Comment 2, Sections 2.1 through 2.3 [pp. 21 to 38] Comment 3, entire ML } NO ce! a8 468—497 Comment 4, entire Sy | 5 | sneer? 497-503 Comment 5 ioe OSG) Fae ee 503-532 Comment 7, Section 7.5 Ss See 532-536 Comment 7, Section 7.7 fom, OR 0 Oe 536-539 Exhibit 2, MJ Bradley & Associates LLC and Analysis Group, “Ensuring a Clean, Modern, Electric Generating Fleet while Maintaining Electric System Reliability” (Aug. 2010) -— Entire report, no attachments [pp. 1 to 24]. Exhibit 4, NESCAUM Report, “Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal-Fired Power Plants” (Mar. 31, 2011) — Executive Summary Oe TT ie VOLUME 3 OF 4 Exelon Corporation, Comments on the National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units; Proposed Rule Docket No. EPA-HQ-OAR-2009-0234-17651 Part 2 of 3 August 4, 2011 Excerpts Exhibit 10, MJ Bradley Report Update -— Entire report [pp. 1 to 20] Exhibit 11, Tierney and Cicchetti Peer Review of EEI Report — Entire report [pp. 1 to 13] 666-685 Exelon Corporation, Comments on the National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units; Proposed Rule, Docket No. EPA- HQ-OAR-2009-0234-17650, Part 3 of 3 August 4, 2011 Excerpts Exhibit 21 — Cicchetti Report ~— Entire report Exhibit 23 — Environmental Health & Engineering Inc. Report — Executive Summary and Sections 1.0 to 3.3 [pp. 1 to 22] 755-796 VOLUME 4 OF 4 New York Department oof Environmental Conservation comments, EPA-HQ-OAR-2009-0234-17796 August 4, 2011 Excerpts Cover letter 797-801 eee eee eee eee ee eee eT eee CORE PR REE EEE He eee Comments of the Utility Air Regulartory Group August 4, 2011 Excerpts Attachment 15 [pp. 6, 12, 15, 16] 807-810 eee ee eee Letter from Dr. Deborah Swackhamer and Dr. Stephen Roberts, Science Advisory Board to Lisa Jackson, Administrator, U.S. EPA, EPA-OAR-2009-0234-18487 — Text only Sept. 29, 2011 811-814 Tee eee eee eee CeCe eee ee ee eee ee ee eee Supplement to the Non-Hg Case Study Chronic Inhalation Risk Assessment In Support of the Appropriate and Necessary Finding for Coal- and Oil-Fired Electric Generating Units EPA-HQ-OAR-2009-0234-19912 Novembcr 2011 Excerpts 3. Chronic Inhalation Risk Assessment i ah 815-817 i See, Tet 818 _ 1 (peaoures qhwoy jenuuy yee} AINIIOW JO QI/g) [BuOT WAY _suotonpey sone A103048¢) SSOUGATIIO DY -380) fenueg =| (BUONBN [eHUMO4 senbruyre |, [OUO) AmIUe;y SNjO% | JOrequINN | auMog Amaseyy $aji0Naj8) 9IINOG pI}de[9g 10} 8380.) PUW SUOFINpeyY UOlSefug Ande [¥jGeI0g ZF 21981 [6-p 2F¥4) lg 58 Table 4-2 presents the four source categories for which a control technology and cost analysis was performed. The selection of a particular type of control for the cost analysis should not be construed to mean that the U.S. EPA has selected, or has preference for, this technology for a given source category. The table presents the number of facilities in each category and the percent contribution of each to the national inventory. Potential national mercury reductions, potential national control costs and cost- effectiveness estimates are also presented. These estimates are based on the assumption that all plants within a source category will achieve the same reductions and incur the same costs as the model plants used in the analysis. Because this assumption would not be applicable in all circumstances, the estimates of potential reductions and costs should be used only for relative comparisons among the source categories to give an initial indication as to where mercury controls could provide the most emission reduction for the least cost. The cost of mercury control incurred by any specific facility may be underestimated by the cost analysis presented in this Report because of variability inherent in the assumptions that were made in the analyses. These assumptions include the efficiency of the various control techniques for reducing mercury, the amount of mercury in the flue gas stream and other site-specific factors such as down-time and labor costs. In addition, costs for monitoring and recordkeeping were not included in the cost analyses. These requirements would be specific to a regulatory action. On the other hand, the costs represent retrofit application of controls. 59 Installation of controls at new facilities can be significantly less expensive than retrofitting an existing facility. The estimates of cost for mercury reductions also do not illustrate two important considerations. One is that, as presented, all of the cost of control could mistakenly be attributed to mercury removal. As described previously in this Report, many of these controls achieve reductions of other pollutants as well (e.g., acid gases, dioxin, other metals). In some cases (e.g., the emission guidelines for MWI), the choice of control technology or control strategy is aimed at reducing pollutants other than mercury. In these cases, there is a co-control benefit of mercury reduction. The benefits of reducing other pollutants should be considered when interpreting the mercury control costs. Second, the technologies available for mercury control represent’ relatively new applications of these technologies. Thus, in the future, it is likely that as new or emerging technologies develop, the cost-effectiveness of control will improve. Air pollution control and prevention techniques are continuously under development and improvement. There is a fairly rapid pace of innovation in the air pollution control sector. The demand for cleaner products and cleaner processes that lower overall costs, combined with the necessity for improved air and water quality, create strong incentives for technological innovation and a growing market for such innovations. As the demand for more innovative, cost-effective and cost-saving technologies increase, new technologies will move from the research and development or pilot program phase to commercial availability. 60 While existing technology will play a key role in reducing mercury from some sources, emerging technology may be more appropriate for others. Innovations in environmental policies may also play a key role in developing a rational management strategy for mercury. These innovations could include multi-media approaches, greater emphasis on pollution prevention, regional control strategies and optimization of co-control opportunities. fe @ @ 61 United States Environmental! Protection Agency Office of Air Quality Planning and Standards Research Triangle Park, NC 27711 EPA-453/R-98-004a February 1998 Air EPA Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units — Final Report to Congress Volume 1. [Page ES-1] EXECUTIVE SUMMARY ES.1 LEGISLATIVE MANDATE In section 112(n)(1)(A) of the Clean Air Act, as amended (the Act), Congress directs the United States Environmenta! Protection Agency (EPA) to: “... perform a study of the hazards to public health reasonably anticipated to occur as a result of emissions by electric utility steam generating units of ... fhazardous air 62 pollutants} ... after imposition of the requirements of this Act.” Section 112(a)(8) of the Act defines an “electric utility steam-generating unit” as “any fossil-fuel—fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electricity for sale.” A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale is also considered an electric utility steam-generating unit (i.e., utility unit). Section 112(n)(1)(A) also requires that: e The EPA develop and describe alternative control strategies for hazardous air pollutants (HAPs) that may warrant regulation under section 112; and e The EPA proceed with rulemaking activities under section 112 to control HAP emissions from utilities if EPA finds such regulation is appropriate and necessary after considering the results of the study. ES.2 REGULATORY DE’ ERMINATION This report does not contain a determination as to whether or not regulations to control HAP emissions from utility units are appropriate and necessary. The Agency has deferred the regulatory determination until a later date. 63 ES.3 OVERVIEW APPROACH TO COMPLETING THE STUDY The study included mumerous separate and interrelated analyses. First, HAP emissions test data were gathered from 52 utility units (i.e., boilers), including a range of coal-. oil-, and natural gas-fired utility units. Second, the emissions test data along with facility specific information (e.g., boiler type, control device, fuel usage) were used to estimate HAP emissions from all 684 utility plants in the United States (U.S.). Third, a screening level hazard/risk assessment was completed to prioritize the HAPs for further analyses. Fourth, various priority HAPs were analyzed for inhalation and [Page ES-2] multipathway exposures and risks and other potential impacts. In addition, potential control strategies were analyzed for the priority HAPs. The overall summary of the study is presented in Figure ES-1. This report presents the findings of the study. The primary components of this report are: (1) a description of the industry; (2) an analysis of emissions data; (3) an assessment of hazards and risks due to inhalation exposures to 67 HAPs; (4) assessments of risks due to multipathway Gnhalation plus non-inhalation) exposures to four HAPs (radionuclides, mercury, arsenic, and dioxins); and (5) a discussion of alternative control strategies. The study was based primarily on two scenarios: (1) 1990 base year emissions; and (2) 2010 emissions. In addition, emissions for 1994 were estimated using 64 the most recent data. The 1990 scenario was chosen since that was the year the Amendments to the Act were passed and was the latest year for which utility operational data were available at the time the study was initiated. The 2010 scenario was selected to meet the section 112(n)(1)(A) mandate to evaluate hazards “after imposition of the requirements of the Act.” Primarily, this meant assessing the hazards after the acid rain program is in place. The 2010 scenario also included estimated changes in HAP emissions resulting from projected trends in fuel choices and projected increases in electric power demands. However, the effects of other on-going or potential activities that were not factored into the 2010 projections (e.g., industry restructuring, new ozone and particulate matter [PM] standards, global climate change programs) may result in the 2010 projections being either underestimated or overestimated. ES.4 EMISSIONS DATA ANALYSIS A total of 684 utility plants (j.e., utilities) were identified as meeting the criteria for the study in 1990 in the U.S. These utilities are fueled primarily by coal (59 percent of total units), oil (12 percent), or natural gas (29 percent). Many plants have two or more units and several plants burn more than one type of fuel (e.g., contain both coal- and oil-fired units). In 1990, there were 426 plants that burned coal as one of their fuels, 137 plants that burned oil, and 267 plants that burned natural gas. Emission estimates for the years 1990, 1994, and 2010 were based on emissions test data from 52 units obtained from extensive emission tests by the 65 Electric Power Research Institute (EPRI, the Department of Energy (DOE), the Northern States Power Company, and the EPA. The testing program was designed to test a wide range of facility types with a variety of control scenarios; therefore, the data are considered generally representative of the industry. However, there are uncertainties in the data because of the small sample sizes for specific boiler types and control scenarios. 31 > ecm EEL IO Suin 90-36 & Oh IN 20 OLE) PED Ried 4 @BUELID ON - SIN AOU) Depa g 198US 4 - JA(8O8 30 0] GN eoUepRU) WO - ARAB! 5 0 GON CUED) BO - sAyeeewO © | Oh Agere @ Oy | PesPeny soUEpRU) MOD - TO QW euepen) poy qn eey sures eesy rey Bly At Wikg ORY FD Fy IN SEneey Weweseery Hey Bas fy way sr) ft VORA OD fy DaurOs > 7 UD 0 ‘By IN) Sum sine jn soon in i . JUSWSSESSY YS}YW/eINSOdxy AemyedNW JUCWISSESSY YS/YW/eUNSOdxX y VO;/eYU a — 4HAOH - 4 penal PSYUNUEP! SdHVH PL- SOB] jOHUE}OY jO kunaueyy - SdVH ®8ZRLOLd, 0} MOABY GUM)BIO}) 7 - eehieuy teSmeng weowssessy Bujueeiog 4H Pus DH lO.QUOD SAQBWweyy a POWWSP| SdH 19 - SUUN ZS Wod, BYEQ 198) - 'S'N Ul SWULid 7RQ 40} SBJEUINISZ SUO!SS}WS - { sishjeuy e12Q Sucjssw3 sesfjeuy Apnjg S2jxo 4 sry Ayiien JO BANJONIYS [JEIGAQ “}-SFSANBIy fo.c9 assy) 99 67 [Page ES-4] These test data provided the basis for estimating average annual emissions for each of the 684 plants. A total of 67 of the 188 HAPs listed in section 112 of the Act were identified in the emissions testing program as potentially being emitted by utilities. Tables ES-1 and ES-2 present estimated emissions for, respectively, a subset of priority HAPs for 1990, 1994, and 2010, and for a set of characteristic boilers for 1994. Although the EPA used average annual emissions estimates in assessing long-term exposures to individual HAPs on a national basis, emissions test data were not available for each utility in the U.S. Therefore, estimates for individual plants are particularly uncertain. Based on an uncertainty analysis, the average annual emissions estimates are expected to be roughly within a factor of plus or minus three of actual annual emissions. However, even this uncertainty analysis had limitations. For example, the uncertainty analysis did not include data on potential upsets or unusual operating conditions; therefore, the range of uncertainty could be greater. ES.5 GENERAL APPROACH TO EXPOSURE AND RISK ASSESSMENT Most of the risk assessment focused on inhalation exposure. All 67 HAPs were assessed for inhalation exposures, at least at a screening level. For many of the 67 HAPs, inhalation exposure is believed to be the dominant exposure pathway. However, for HAPs that are persistent and/or bioaccumulate, and are toxic by ingestion (or are 68 radioactive), the non-inhalation exposure pathways could be more important. Based on a screening and prioritization assessment, which is described below, the EPA identified four high priority HAPs (radionuclides, mercury, arsenic, dioxins) to assess for noninhalation exposures. In addition, cadmium and lead were identified as next highest priority. Multipathway assessments are presented for radionuclides, mercury, arsenic, and dioxins. The other two HAPs (lead and cadmium) were examined qualitatively for their potential for multipathway hazards. ES.6 SCREENING ASSESSMENT As outlined in Figure ES-1, EPA initially conducted a screening assessment that considered inhalation and non-inhalation exposure routes for all 67 HAPs to identify priority HAPs for more detailed assessment. To screen for inhalation exposures, the EPA used the Human Exposure Model (HEM) to model the 67 HAPs from all 684 utility plants utilizing generally conservative assumptions (i.e., assumptions that are more likely to overestimate rather than underestimate risks) to estimate inhalation risks for maximally exposed individuals (MEIs). 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For non-inhalation exposures, the 67 HAPs were prioritized by considering five criteria: (1) persistence; (2) tendency to bioaccumulate; (3) toxicity; (4) emissions quantity; and (5) radioactivity. Based on this screening assessment, a total of 14 HAPs were identified as priority. Twelve HAPs (arsenic, beryllium, cadmium, chromium, manganese, nickel, hydrogen chloride [HC], hydrogen fluoride [HF], acrolein, dioxins, formaldehyde, and radionuclides) were identified as priority pollutants for further study based on potential for inhalation exposures and risks. Four of these 12 HAPs (arsenic, cadmium, dioxins, and radionuclides) plus 2 additional HAPs (mercury and lead) were considered priority for multipathway exposure); of these 6 HAPs, 4 (arsenic, mercury, dioxins, and radionuclides) were identified as the highest priority to assess for [Page ES-7] multipathway exposures and risks. Overall, a total of 14 of the 67 HAPs were considered priority. The other 53 HAPs were not evaluated beyond the screening assessment. @ The RC is an estimate (with uncertainty spanning perhaps an order of magnitude) of the daily inhalation exposure of the human population (including sensitive subgroups) that is likely to be without appreciable risk of deleterious effects during a lifetime. 72 ES.7 INHALATION RISK ASSESSMENT -- LOCAL ANALYSIS The EPA estimated inhalation exposures and risks due to dispersion of HAP emissions within 50 kilometers (km) of each of the 684 plants (i.e., local analysis). For 13 of the 14 priority HAPs, the HEM was used; for radionuclides, the Clean Air Act Assessment Package-1993 (CAP-93) model was used. The HEM exposure modeling conducted for the inhalation risk assessment was very similar to the modeling conducted for the screening assessment. The same default options and same input data were used. However, there is one important difference. For the inhalation risk assessment, a distinction was made between urban and rural locations. If a plant is located in an urban area, it was modeled using the urban mode (i.e., dispersion is assumed to be characteristic of emissions emitted by a facility in an urban location where there are buildings nearby). Dispersion of the pollutant plume in an urban area is expected to exhibit greater turbulence because of heat transfer and obstacles (i e., large buildings). If a plant is located in a rural location, it was modeled using the rural mode (i.e., dispersion is assumed to be characteristic of a facility located in a rural location). In the screening assessment, all plants were modeled using the urban default because using the urban default typically leads to more conservative (i.e., higher) estimates of human exposures, which is appropriate for a screening assessment. However, using the urban and rural distinction is believed to reflect more realistic conditions. 73 The cancer risks for all gas-fired plants were well below one chance in one million (i.e., o oe a ° oe eer r oof . ——--—_ ——_— — — — —~- -—- —————+ 90¢ Sd WH ep}jONUo|pel-UOU d1UeBOUIDIe9 jy (HIV JO SAS Ag) S48Iy JENPIIpPU) LUNWIxey jO SOAS] SNOLBA Bulsog 8811)/117) PO4j4-/BOD JO seqUUNNY "7-Sa eunBiy (6-Sqa ese) oO X . 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This section identifies several of the important areas in which further research or scientific and technical work is needed. 14.7.1 Emissions Data for Dioxins Emissions data for dioxins were available from only eight of the tested utility plants. Therefore, there are greater uncertainties with the dioxin emissions than for many of the other HAPs. All types of utility units were not tested (e.g., there are no data available from coal-fired units with hot-side ESPs). 14.7.2 Speciation of Nickel and Chromium There are significant uncertainties regarding the forms of nickel being emitted from oil-fired utilities and the health effects associated with those different forms. Therefore, further research and evaluation of the emissions to determine what forms are being emitted and the health effects associated with those different forms would be of value. Further evaluation of chromium speciation is also needed. 14.7.3 Multipathway Risk Assessment As mentioned previously, further work is needed to study the risks due to multipathway exposure to 136 HAPs that are persistent and bioaccumulate. Arsenic and dioxins are two HAPs identified as priority for further multipathway assessment. 14.7.4 Long-range Transport Exposures Uncertainties remain regarding long-range transport of HAPs. Further modeling and evaluation could be helpful to assess the impacts of long-range transport of HAPs from utilities. 14.7.5 Mercury Issues There are numerous areas regarding mercury that may need further research, study, or evaluation. A number of potential areas for further study include the following: e review the estimates of the levels of exposure to mercury associated with subtle neurological endpoints; [Page 14-9] e quantify and/or evaluate the relationship between a change in United States mercury emissions and the resulting change in methylmercury levels in fish; e evaluate actual consumption patterns and estimates of the methylmercury exposure of the subpopulations of concern; e gather additional data on the mercury content of various types of coal; e establish improved methods for measuring mercury concentrations in water; 137 e study the occupational, dietary, and behavioral factors that affect mercury exposures for people who are determined to be exposed above a threshold of concern; e study the public health and environmental benefits that would be expected by reducing mercury emissions from utilities; e evaluate and/or research control technologies or pollution prevention options that are available, or will be available, that could potentially reduce mercury emissions and what are the costs, economic impacts, and feasibility of those options; e evaluate how other regulations, programs, and activities (e.g., acid rain program, electricity restructuring, NAAQS, climate change) affect mercury emissions; e gather additional data on mercury emissions (e.g., how much is emitted from various types of utility units, how much is divalent vs elemental mercury, and how do factors such as control device, fuel type, and plant configuration affect emissions and speciation); and e study how much mercury is emitted from natural sources and past anthropozenic sources. 14.7.6 Projections to the Year 2010 There are. significant uncertainties and unknowns in the emissions and misk projections made to the year 2010 (e.g., impact of industry restructuring; impact of State efforts to regulate restructuring; impact of any climate change 138 initiatives). Further research and evaluation in this area is needed. 14.7.7 Ecological Risks The effects of HAPs on wildlife, endangered species, and terrestrial and aquatic ecosystems were not evaluated in this study. Although not mandated by section 112(n)(1)(A), further evaluation of [Page 14-10} ecological risks due to HAP emissions would be needed to fully evaluate the impacts of utility HAP emissions. 14.7.8 Criteria Pollutant and Acid Rain Programs Further evaluation is needed to assess the impacts of the Acid Rain and Criteria Pollutant programs (e.~, impact of revisions to the PM-fine and ozone NAAQS; impact of Ozone Transport Assessment Group [OTAG] activities) on HAP emissions. 14.7.9 Short-term Emissions A limited assessment of short-term exposures was completed. However, further evaluation of short- term releases, especially highend, peak releases, could be useful to fully assess the potential impacts to public health due to emissions of HAPs (particularly HCl and HF) from utilities. 139 Federal Register /Vol. 69, No. 20 / Friday, January 30, 2004 / Proposed Rules [Page 4657} xx«* C. What Are the Health Effects of HAP Emitted From Coal- and Oil-Fired Utility Units? Data collected during development of the proposed section 112 rule show that coal- and oil- fired Utility Units emit a wide variety of metal, organic, and inorganic HAP, depending on the type of fuel that is combusted. Today’s proposed rules, both under CAA section 111 and 112, would protect air quality and promote the public health by reducing emissions of Hg and Ni from coal- and oil- fired Utility Units. Exposure to Hg and Ni at sufficiently high levels is associated with a variety of adverse health effects. The EPA cannot currently quantify whether, and the extent to which, the adverse health effects occur in the populations surrounding these facilities, and the contribution, if any, of the facilities to those problems. However, to the extent the adverse effects do occur, either of today’s proposed actions would reduce emissions and subsequent exposures. Following is a summary of the health effects for the Hg and Ni emissions that would be reduced by either of the proposed rules. Mercury. Mercury is n persistent, bioaccumulative toxic metal that exists in three forms: elemental Hg (Hg®), inorganic Hg (Hg**) compounds (primarily mercuric chleride), and organic Hg compounds (primarily methylmercury). Each form exhibits different health effects. Various 140 major sources may release elemental or inorganic Hg; environmental methylmercury, the form of concern for this rulemaking, is typically formed by biological processes after Hg has precipitated from the air and deposited into water bodies. Mercury is toxic to humans from both the inhalation and oral exposure routes. In the proposed rulemaking, we focus [Page 4658} on oral exposure of methylmercury as it is the route of primary interest for human _ exposures. Methylmercury is a_ well-established human neurotoxin although, as with many chemicals, the scientific community is divided on the specific dose and frequency of exposure required to elicit adverse effects. According to the NAS, chronic low-dose prenatal methylmercury exposure has _ been associated with poor performance on neurobehavioral tests in children, including those tests that measure attention, visual-spacial ability, verbal memory, language ability, fine motor skills, and intelligence. Furthermore, it has _ been hypothesized that there is an association between methylmercury exposure and an increased risk of coronary disease in adults; however, this hypothesis warrants further study as the few studies currently available present conflicting results. (NEJOM; 2002; Yoshizawa, 2002; Guallar, 2002; Salonen, 1999; Salonen, 1995; Bolger, 2003). Fish consumption dominates the pathway for human and wildlife exposure to methylmercury. There is a great deal of variability among individuals in fish consumption rates. Critical elements in 141 estimating methylmercury exposure and risk from fish consumption include the species of fish consumed, the concentrations of methylmercury in the fish, the quantity of fish consumed, and how frequently the fish is consumed. The typical U.S. consumer eating a wide variety of fish from restaurants and grocery stores is not in danger of consuming harmful levels of methylmercury from fish and is not advised to limit fish consumption. Those who regularly and frequently consume large amounts of fish, either marine or freshwater, are more exposed. Because the developing fetus may be the most sensitive to the effects from methylmercury, women of child-bearing age are regarded as the population of greatest interest. The EPA, Food and Drug Administration, and many States have issued fish consumption advisories to inform this population of protective consumption levels. The EPA’s 1997 Mercury Study RTC supports a plausible link between anthropogenic releases of Hg from industrial and combustion sources in the U.S. and methylmercury in fish. However, these fish methylmercury concentrations also result from existing background concentrations of Hg (which may consist of Hg from natural sources, as well as Hg which has been re-emitted from the oceans or soils) and deposition from the global reservoir (which includes Hg emitted by other countries). Given the current scientific understanding of the environmental fate and transport of this element, it is not possible to quantify how much of the methylmercury in fish consumed by the U.S. population is contributed by U.S. emissions relative to other sources of Hg (such as natural sources and 142 reemissions from the global pool). As a result, the relationship between Hg emission reductions from Utility Units and methylmercury concentrations in fish cannot be calculated in a quantitative manner with confidence. In addition, there is uncertainty regarding over what time period these changes would occur. This is an area of ongoing study. Given the present understanding of the Hg cycle, the flux of Hg from the atmosphere to land or water at one location is comprised of contributions from: the natural global cycle; the cycle perturbed by human activities; regional sources; and local sources. Recent advances allow for a general understanding of the global Hg cycle and the impact of the anthropogenic sources. It is more difficult to make accurate generalizations of the fluxes on a regional or local scale due to the sitespecific nature of emission and deposition processes. Similarly, it is difficult to quantify how the water deposition of Hg leads to an increase in fish tissue levels. This will vary based on the specific characteristics of the individual] lake, stream, or ocean. As part of routine U.S. population surveillance, the U.S. Centers for Disease Control (CDC) assessed Hg concentrations in blood of over 1,500 women of child-bearing age. A recent analysis of these data reported that about 8 percent of these women of child-bearing age have levels of Hg in their blood that are at or above the U.S. EPA’s RfD. The CDC also surveyed the same group of women about their eating habits. The surveyed women reported eating shrimp and tuna more frequently than other fish and shellfish options. Hg concentrations in seafood may 143 be largely responsible for elevated levels of Hg in U.S. women of child-bearing age. We have little information about how Hg emissions from U.S. power plants may affect Hg concentrations in shrimp, tuna, and other marine fish. We seek comment on this issue and in particular, any data or other information that would allow us to better estimate the extent to which today’s proposal would reduce blood Hg concentrations in U.S. women. Recent estimates (which are highly uncertain) of annual total global Hg emissions from all sources (natural and anthropogenic) are about 5,000 to 5,500 tons per year (tpy). Of this total, about 1,000 tpy are estimated to be natural emissions and about 2,000 tpy are estimated to be contributions through the natural global cycle of re-emissions of Hg associated with past anthropogenic activity. Current anthropogenic emissions account for the remaining 2,000 tpy. Point sources such as fuel combustion; waste incineration; industrial processes; and metal ore roasting, refining, and processing are the largest point source categories on a world-wide basis. Given the global estimates noted above, U.S. anthropogenic Hg emissions are estimated to account for roughly 3 percent of the global total, and U.S. utilities are estimated to account for about 1 percent of total global emissions. (Utility RTC at 7—1 to 7-2.) Nickel. Nickel is a natural element of the earth’s crust; therefore, small amounts are found in food, water, soil and air. Food is the major source of Ni exposure. Ni is an essential element in some animal species. Individuals may also be exposed to Ni if they are employed in occupations involved in Ni 144 production, processing, and use, or through contact with every day items such as Ni-containing jewelry and stainless steel cooking and eating utensils, and by smoking tobacco. The route of human exposure to Ni that we are concerned with in this rulemaking is Ni that is found in ambient air at very low levels as a result of releases from oil-fired Utility Units. The differing forms of Ni have varying levels of toxicity. There is great uncertainty about the different species of Ni emitted by Utility Units. Respiratory effects, including a type of asthma specific to Ni, decreased lung function and bronchitis have been reported in humans who have been occupationally exposed to high-levels of Ni in air. Animal studies have reported effects on the lungs and immune system from inhalation exposure to soluble and insoluble Ni compounds (nickel oxide, subsulfide, sulfate heptahydrate). Soluble Ni compounds are more toxic to the respiratory tract than less soluble compounds. The EPA has not established a reference concentration (RfC)for Ni. No information is available regarding the reproductive or developmental effects of Ni in humans, but animal studies have reported such effects, although a consistent doseresponse relationship has not been seen. Human and animal studies have reported an increased risk of lung and nasal cancers from exposure to Ni refinery dusts and Ni subsulfide. The EPA has classified Ni carbonyl as a Group B2, probable human carcinogen based on lung tumors in animals. (see [Page 4659] http: //www.epa.gou/ttn/atw/hlithef/ nickel.html). 145 We ask for comment on all aspects of our proposed revised determination that it is necessary and appropriate to regulate Ni emissions from oil- fired Utility Units under section 112. In particular, we ask for comments and additional information related to the speciation of Ni compounds directly emitted by oil-fired Utility Units and those that may be formed through atmospheric transformation, as well as information on potential health effects. We also ask commenters—especially current owners and operators of potentially affected oil-fired units—to provide information on the current operating status and anticipated mode of operation in the future of potentially affected oil-fired Utility Units, including current control technology. To the extent possible, we would like to have up-to-date information on fuel use, emissions, stack parameters and other location- specific data that would be relevant to the assessment of emissions, dispersion, and ambient air quality. We also ask for comment on our finding in the Utility RTC that only 11 of 137 oilfired Utility Units considered in the Utility RTC posed an inhalation risk to human health greater than one in a million (1 * 10°) and whether data exists as to whether emissions from these plants no longer pose such risk. 146 Federal Register /Vol. 70, No. 59 /Tuesday, March 29, 2005 /Rules and Regulations [Page 16019} eek * F. Fish Tissue Levels of Methylmercury Modeled To Result After Implementation of CAIR and CAMR This section describes the amounts of Utility Unit attributable Hg deposition onto watersheds (termed HUC), as well as the Utility-attributable methylmercury in fish tissue, all under the various control scenarios modeled. 1. Utility-Attributable Hg Deposition Patterns The air quality modeling shows that total Hg deposition is not highly impacted by utility deposition. The small size of this impact is evident when utility emissions are, in effect, zeroed out in the 2001 base case. The following tables summarize impacts on total Hg deposition and Hg deposition attributable to Utility Units. (siejeu erenbs sed sarviSoiorw ul pesseidye as¥ sytun [ly) 02 LIZ 99° sol | came neaentennacineganestnnguasbousneeensnenncensuesepeeseces venenmnenb a[ueaied 166 66°0 lest ee cores |_—_Cs nme ne nena eennaanenenennneetnnsnnnene omueased 9s ore ores an ‘ere (i caacnecanaamenrananinmsies quent en ove ore atts ne | | speenneemmenceoninersmsersinet Foren ee a am — = F | seapaiesinestieliganpioncipnchligheplatbpieiealindiineelit ne saQwaiayy | Huemanbey | AVS qm) WAVD 0202 | UINVD 0%0Z | eswoesMG OZOZ — a#w aeeY 1002 [1949] 8-ONH 24) % payesad3e) NOLLISOdad OH ATAVLASIMLLY ALITILA YOd SOLLSILVLS AUVWANS “1A FTEVL (eye arenbs sed swecdourw UI pessaudxe ase sy1UN |[y) ones loows loves “e082 ris 9 te F eee cquaceaed wes — ous over Ce Co equeased wigs enet eet ant | es — ate _— arve ere osenenreenereenneenenauanaapgas ore eve we 69 ss nnenensensne seen menapagaas yno (IVS 4a) yo o1ez ose AVI) OZOT | 9#¥O Be~q OZOT | AIIM LOOT | 28H e8~q 100Z | [1949] 8-ONH 893 03 payesoi33y) NOLLISOdad DH TVLOL YOd SOLLSILVLS ANVNWOS— PLA FTEVL ['3U09 §LO9T 938q) Lei 148 [Page 16019 cont.} The median deposition level is reduced by only 8 percent when utilities emissions are zeroed out in 2001, suggesting that utilities are not a major source of Hg deposition in most HUCs. Even so, at HUCs with the highest deposition levels, zeroing out utilities reduces the 99th percentile deposition level by 16 percent, suggesting that there are relatively larger impacts of utilities in high deposition areas. By 2020, after implementation of CAIR, significant reductions in deposition attributable to utilities occurs. HUCs with high levels of utility deposition receive a larger reduction in Utility- attributable Hg deposition relative to HUCs with a relatively small level of Utility-attributable deposition. Specifically, CAIR results in a 75 percent reduction in the 99th percentile of Utility- attributable deposition, and a 20 percent reduction in the 50th percentile. CAIR also shifts the distribution of utility-attributable deposition. In the 2001 base case, 10 percent of HUCs had greater than 20 percent of deposition attributable to utilities. In the 2020 post-CAIR base case, no HUCs had greater than 20 percent of deposition attributable to utilities, and 90 percent had less than 9 percent of deposition attributable to utilities. [Page 16020] Additional reductions in Hg emissions due to the CAMR requirements result in relatively small additional shifts in the distribution of deposition. Additional emissions reductions due to the CAMR requirements result in a small additional reduction in the number of HUCs with a high percentage of 149 utilityattributable emissions. (The incremental impact of the CAMR alternative relative to the promulgated CAMR requirements is very small.) 2. EGU-Attributable Methylmercury Fish Tissue Levels The following _ tables summarize the methylmercury fish tissue levels associated with the various Utility Unit Hg emissions scenarios. All units refer to mg (of methylmercury) per kg (fish tissue), or parts per million (ppm). As a frame of reference, it should be noted that EPA’s default water quality criterion is 0.3 mg/kg. (Cansexy ysy 84 29d AmoseuryAqjem 3a wt az syTun Ty) en'0 600 O10 920 T ssoovotaeeseonindnnapstethienssieyhemnessendeatiinsstatebabine apauecsed yee £0°0 00 £00 Ite OER EERE RNR REE EERE EE EERE EE TERE O EERE ES EE HEE EEE EEE EEE TEE EEE EEE atQueasad 7306 10'0 100 ! 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In the 2001 base case, as a result of all international and U.S. emissions, and before U.S. utilities implement reductions from CAIR or CAMR, the 50th percentile of the sample points had an estimated methylmercury fish tissue concentration of 0.25 mg/kg. The 90th percentile water body had an estimated methylmercury fish tissue concentration of 0.90 mg/kg, and the 99th percentile had 1.80 mg/kg. The amount of methylmercury attributable solely to utilities in the 2001 base case, which becomes evident when utilities are zeroed out, is of course much smaller. The 50th percentile of the sample points had an estimated methylmercury fish tissue concentration. attributable solely to utilities, of 0.03 mg/kg. The 90th percentile had 0.11 mg/kg, the 99th percentile had 0.26 mg/kg, and the maximum individual sample point had 0.85 mg/kg. It should be recalled that EPA recommends the water quality criterion of 0.3 mg/kg as a level that, given fish consumption at the 90th percentile level, would result in exposure levels below the RfD. For present purposes, EPA does not consider the water quality criterion of 0.3 mg/kg as a bright-line test for evaluating fish tissue methylmercury levels attributable to U.S. Utility Units. Rather, the criterion serves as establishing a broad frame of reference, that serves to place into context both the overall methylmercury fish tissue levels (which are attributable to methylmercury from all sources) and the methylmercury levels attributable to Utility Units. 152 These results indicate the relatively small percentage of U.S. utility contribution to U.S. fish tissue methylmercury levels. b. 2020: Utilities With CAIR Reductions. EPA’s modeling shows that in 2020, as a result of all international and U.S. emissions, and with U.S. utilities implementing reductions from CAIR (but not CAMR), the 50th percentile of the sample points is projected to have a methylmercury fish tissue concentration of 0.21 mg/kg. The 90th percentile is projected to have 0.79 mg/kg, and the 99th percentile is projected to have 1.64 mg/kg. The amount of methylmercury in fish attributable solely to utilities in 2020, after implementation of the CAIR reductions (but, again, before CAMR), of course is smaller. The 50th percentile of the sample points is projected to have fish tissue concentration, attributable solely to utilities of 0.01 mg/kg. The 90th percentile is projected to have 0.03 mg/kg, the 99th percentile is projected to have 0.10 mg/kg, and the maximum individual sample point (i.e., the one with the highest methylmercury levels) is projected to have 0.25 mg/kg. Again, using the 0.3 mg/kg methylmercury water quality criterion as a broad frame of reference serving to place in context both the overall methylmercury fish tissue levels (attributable to methylmercury from all _ sources) and _ the methylmercury fish tissue levels attributable to Utility Units, it is clear that the latter levels, following implementation of CAIR, are low. 153 c. 2020: Utilities with CAMR Controls. The CAMR level of controls achieve further, albeit small, reductions in methylmercury fish tissue concentrations. Compared to the CAIR controls, the CAMR controls would further reduce, in 2020, methylmercury fish tissue concentrations by, in the 99th percentile, 0.01 mg/kg. d. 2020: Utilities with Alternative CAMR Controls. EPA evaluated, but did not adopt, a slightly tighter level of CAMR controls. These alternative [Page 16021] CAMR controls would have achieved still further, albeit, again small, reductions in Hg deposition and in fish tissue methylmercury levels. Compared to the CAIR controls, these alternative CAMR controls would reduce methylmercury fish tissue levels in 2020 by, in the 99th percentile, 0.02 mg/kg. 49 5. Overall Impact of CAIR and CAMR Controls on Utility Unit Hg Emissions As described in the CAIR rule, CAIR reduces EGU Hg emissions from pre- CAIR levels by a substantial percentage. CAMR reduces Utility Unit Hg emissions, from CAIR levels, by 27 percent. CAMR reduces ionic Hg emissions, those that are most likely to result in local and regional deposition, by 17 percent relative to CAIR levels. 49 A detailed discussion of the control alternatives we considered and the reason for our final selection is contained in the preamble to the final CAMR. 154 These reductions tend to occur from the largest sources. That is, the larger the source of Hg emissions, the more likely it is to implement CAIR or CAMR controls, and therefore the more likely it is to reduce its Hg emissions. More specifically, under the cap-and-trade system, the marketplace tends to direct controls to the largest emitters because those emitters can achieve the most. cost-effective reductions. Compared to smaller emitters, these larger emitters have an incentive to implement more stringent controls, thereby reducing their emissions further below the level of their allowances, and thereby generating a larger number of allowances for sale to defray control costs. See “Proposed National Emissions Standards for Hazardous Air Pollutants; and in the Alternative, Proposed Standards of Performance for New and Existing Sources: Electric Utility Steam Generating Units,” 9 FR 4652, 4702-— 03 (Jan. 30, 2004). G. Exposure to Utility-Attributable Methylmercury Levels in Fish Tissue CAIR reduces median Utilityattributable fish tissue methylmercury levels, from pre-CAIR levels, by 67 percent. CAIR reduces the 99th percentile Utility-attributable fish tissue methylmercury levels, from pre-CAIR levels, by 60 percent. CAMR reduces median Utility-attributable fish tissue methylmercury levels, from CAIR levels, by 12 percent. CAMR reduces the 99th percentile Utility- attributable fish tissue methylmercury levels, from CAIR levels, by 9 percent. As a result of these reductions, after CAIR or CAMR, no sample site remains in which Utility- 155 attributable, emissions cause methylmercury fish tissue levels to exceed 0.3 mg/kg (EPA’s water quality criterion). Even with these reductions, although the levels of methylmercury in fish tissues attributable to Utility Units are small, the magnitude of methylmercury exposure depends on consumption levels and the sensitivity of the individual. For purposes of assessing whether utility Hg emissions are reasonably anticipated to result in hazards to public health, we focused on evaluating utility attributable methylmercury exposures for women of childbearing age in the general U.S. population who consume noncommercial (e.g., recreational) freshwater fish in U.S. waterbodies. This section describes available information as to the consumption levels of women of child-bearing age within the population of recreational fishers who consume at typical levels, and within high- consumption subpopulations; and discusses the amounts of methylmercury that may be ingested as a result of those consumption levels. 1. General Population We believe that only those women of childbearing age who consume noncommercially caught U.S. freshwater fish have the potential for significant exposures to utilityattributable methylmercury. As a result, our assessment of the hazards to public health focuses on those women. 156 2. Recreational Fishers Who Consume Fish At Typical Levels. a. Consumption Levels. For our analysis of recreational freshwater fish consumption, EPA has determined that the sport-caught fish consumption rates for recreational freshwater fishers specified as “recommended” in the EPA’s Exposure Factors Handbook (mean of 8 gm/day and 95th percentile of 25 gm/day), represent the most appropriate values for present purposes. These recommended values were derived based on ingestion rates from four studies conducted in Maine, Michigan, and Lake Ontario (Ebert et al., 1992; Connelly et al., 1996; West et al., 1989; West et al., 1993). These studies are suitable because they included information for annual-averaged daily intake rates for self-caught freshwater fish by all recreational fishers including consumers and non-consumers. The mean values presented in these four studies ranged from 5 to 17 gm/day, while the 95th percentile values ranged from 13 to 39 gm/day. © The EPA “recommended values” were developed by considering the range and spread of means and 95th percent values presented in the four studies. EPA recognizes that use of mean and 95th percentile consumption rates based on these four studies may not be representative of fishing behavior in every state and that there may be regional trends in consumption that differ from the values used in this analysis. However, EPA believes that these four 50 The 39 gm/day value actually represents a 96th percentile value. 157 studies represent the best available data for developing recreational fisher ingestion rates for present purposes. As a result, for today’s purposes of evaluating the potential for health effects for consumers of recreational freshwater fish resulting from exposure to utility-attributable methylmercury, we consider both the mean of 8 gm/day consumption and the 95th percentile amount of 25 gm/day. b. Levels of Consumption Combined with Levels of Utility-Attributable Methylmercury in Fish Tissue. As described above, fish tissue levels of Utility-attributable methylmercury, for virtually all sample points, are only a fraction of the 0.3 mg/kg (fish tissue) water quality criterion. EPA evaluated recreational fish consumers’ exposure to this Utility- Attributable methylmercury by calculating the level of exposure to this methylmercury and comparing it to the RfD when background exposures are not considered. For the purposes of assessing population exposure due solely to power plants, we create an index of daily intake (IDI).The IDI is defined as the ratio of exposure due solely to power plants to an exposure of 0.1 pug/kg bw/day. The IDI is defined so that an IDI of 1 is equal to an incremental exposure equal to the RfD level, recognizing that the RfD is an absolute level, while the IDI is based on incremental exposure without regard to absolute levels. Note that an IDI value of 1 would represent an absolute exposure greater than the RfD when background exposures are considered. At either the mean fish consumption rate of 8 gm/day or the 95th percentile fish consumption rate 158 of 25 gm/day for recreational fish consumers discussed above, and using the 99th percentile methylmercury fish tissue concentration attributable to Utility Unit (and a typical body weight of 64 kg for women of child-bearing age), the calculated Utility- attributable methylmercury exposures are 0.013 pug/kg body weight per day and 0.04 pug/kg body weight per day, respectively. Both calculated exposures are well below the RfD of 0.1 pug/kg body weight per day (an IDI value well below 1). [Page 16022] EPA uses the RfD to place ingestion levels in context. The RfD level of methylmercury ingestion— 0.1 pug/kg body weight—should not be considered a bright line standard above which adverse health effects occur, but rather as an aid in establishing the context for evaluating both overall methylmercury ingestion (arising from methylmercury from all sources) as well as_ Utility- Attributable methylmercury ingestion in light of consumption rates. Our analysis concludes that Utility Unit Hg emissions do not cause hazards to the health of the general public or higher fish consuming recreational anglers. 3. High-Level Fish Consumption Sub- Populations Although exposure to Utilityattributable methylmercury from freshwater fish tissue is quite low for recreational fishers generally, as just described, EPA recognizes that certain’ sub- populations consume higher levels of U.S. freshwater fish. These populations may include a subset of recreational fishers who consume large quantities of fish, individuals who are subsistence fishers, and 159 individuals who are part of certain ethnic groups. EPA is aware that at very high consumption levels, even relatively small concentrations of methylmercury in fish may result in exposures that exceed the RfD. However, as described in the TSD, characterization of fish consumption rates for the highest fish consuming subpopulations (e.g., Native American and other ethnic populations exhibiting subsistence-like consumption) in the context of a larger regional or national analysis is technically challenging. Peer reviewed study data on “these populations is relatively limited, especially when subjected to the criteria outlined in the TSD. Many of the high consumption groups that have been studied are located near the ocean and consequently have a significant fraction of their overall exposure comprised of saltwater fish. In addition, some of these studies provide details on seasonal! consumption rates, but do not integrate these rates to provide an overall mean annual-averaged consumption rate relevant to an RfD-based analysis. Although many of these studies provide mean consumption rates, few have identified specific high- end percentile values (eg., 90th, 95th or 99th percentile consumption rates). Instead, many studies, including a number of non-peer reviewed sources, cite non-specific high-end or bounding point estimates (e.g., the range of consumption rates for the Ojibwe submitted for the CAMR NODA). While these point values can be used in developing high- end bounding scenarios for evaluating risk to these groups, they do not support populationlevel analysis 160 of exposure since they cannot be used to fit distributions characterizing variability in fish consumption rates across these subpopulations (as noted above, modeling of population-level exposures requires that distributions characterizing fish consumption rates across a particular population be developed). An additional challenge in characterizing high- level fish consumption is that care needs to be taken in extrapolating study results from one group to another. This reflects the fact that high-level fish consumption is often tied to socio-cultural practices and consequently consumption rates for a study population cannot be easily transferred to other groups which may have different practices (e.z., practices for one Native American tribe may not be relevant to another and consequently behavior regarding fish consumption may not be generalized). Despite these challenges in characterizing high- level consumption, EPA has developed recommended subsistence-level fish consumption rates of 60 g/day (mean) and 170 g/day (95th percentile) (EPA, 1997, Exposure Factors Handbook). These values are based on a study of several Native American Tribes located along the Columbia River in Washington State. Although these consumption rates are specific to the tribes included in the study and reflect their particular sociocultural practices (including seasonality and target fish species), EPA believes that this study does provide a_ reasonable characterization of highconsuming subsistence-like freshwater fishing behavior (EPA, 1997, Exposure Factors Handbook). Therefore, in the absence of data 161 on local practices, EPA recommends that these consumption rates be used to model high-consuming groups in other locations. It is important to note that, as explained above, application of these subsistence consumption rates outside of the original Columbia River study area could be problematic because it would be difficult to transfer these consumption rates to a different group that might exhibit different fishing behavior. However, these recommended rates can be used to model subsistence scenarios at different locations. Although these subsistence consumption rates are recommended by EPA, commenters (including NODA comments obtained for this rule), have identified alternative consumption rates for specific high consuming groups that are in some instances, higher than these recommended values. For example, a survey by the Great Lakes Indian Fish and Wildlife Commission (GLIFWC) (as referenced in comments to the CAMR NODA) indicates that consumption rates by members of Ojibwe Great Lakes tribes during fall spearing season may range from 155.8-240.7 g/day and may range from 189.6— 292.8 g/day during the spring. EPA has reviewed these comments and does not believe that it would be appropriate to rely on them for purposes this rulemaking. First, the data has not been peer reviewed. Moreover, it is not clear from the comments how many people consume fish at those rates, to what extent those fish consumers are 162 women of childbearing years, and how to annualize these seasonal sales.®! For all the above reasons, and despite comments indicating that some subgroups may have larger short-term consumption rates, EPA believes that the Columbia River-based consumption rates of between 60 g/day (mean) and 170 g/day (95th percentile) are appropriate default values for subsistence fish consumers. 51 As discussed below, the Ojibwe Great Lakes tribes do not appear to be located in areas with high utility-attributable Hg deposition. 163 Technical Support Document (TSD) for the Transport Rule Docket ID No. EPA-HQ-OAR-2009-0234 Coal-to-Gas Conversion (C2G) U.S. Environmental Protection Agency Office of Air and Radiation March 4, 2011 Coal-to-Gas Conversions (C2G) Section V in the preamble to the Toxics Rule discusses coal-to-gas conversion (C2G) as a retrofit technology option to reduce air pollutant emissions. C2G is provided as a retrofit option to all coal boilers larger than 25 MW in EPA’s IPM modeling of the Toxics Rule. This retrofit option is comprehensively modeled with explicit retrofit capital and O&M costs, pipeline extension costs, and heat rate penalties. As mentioned in the preamble, the C2G option was not selected in IPM as an economic choice for coal boilers to comply with the Toxics Rule. This TSD provides a brief explanation of the main reasons why C2G was not an economic choice. The Toxics Rule requires all EGU coal boilers larger than 25 MW to achieve significant reductions in mercury, HCl, and total PM emissions. In addition to the C2G conversion option, there are other retrofit options available in IPM to reduce these emissions. They include activated carbon injection (ACI), flue gas desulfurization (FGD), and dry alkali sorbent injection (DSI, any of which can individually or in combination make a significant reduction in such emissions. 164 Table 1 shows the calculated cost-of-electricity (COE) based on characteristics of a representative actual “model plant” in the Proposed Toxics Rule policy modeling. The model plant represents a 303 MW existing coal unit. The performance and incremental costs of the various retrofit options are based on the parameters of actual retrofits offered to such a unit in the IPM model. had 0% 2 Il rg pseg (GM A/STT) Az1014j98q-JO-380D [BJUEUaIIUT [BIO] ‘OF 00 "0 T'0 Zz (UM I/STTTU) 83805 [any [eWUeUTai9U] pus ose €'0) eT cl Qh (FM W/SIITA) 83805 WYO 9QBUBA [eIUEeMIaIOUT 6'¢ Z0 6 6'0 (QM A/S) $380 paexty [BIUaWaioUy Le elz €1Z eZ BIZ (MQW) 2Ug jong y [eoD [eog [B05 Te0D jang %08 %08 %08 08 (%) 20398,4 Aytoedes £11 %E°LT %E TT %E'TI (%) a38y aBrBYD [eydeD €'0- ee'l Srl 6F'F (MVS) 39%I8y JO WFO eqeuBA = 00 og 80 (AVS) IGOI78Y JO WHO pexty ze II Los Le autjedid Sutpnyout (44 H/$) WYOuJey Jo 3805 yezidep UZO'IT 909'0T 999'0I 69'0I og'O1 (MAMIE) 238Yy 3898} 0€ €0€ £0€ (MVD 2218 yu D2) ‘IOV aoa yup) aseg su0ndy IWANey qued japow peords; B uo suorydo 41301301 10; AIDLIZDE[9-JO-7809 [BJWeUIaIIU] — [ afquy cgT 166 Note that while the combined capital cost and O&M costs for a C2G retrofit could be less than that of a combined retrofit with ACI and either DSI or FGD, the greatly increased fuel costs of C2G cause its total incremental COE ($44.5/MWh) to be between 4 to 22 times the COE impact of the other retrofit options available. The C2G option for this case is therefore uneconomic under the relative fuel cost projections in IPM modeling of the Toxics Rule. The COE comparison allows consideration of the relative cost-effectiveness of using C2G to obtain beyond-the-floor reductions in the emission rates of toxic air pollutants. For example, DSI is assumed to achieve 90% reduction of HCl in the Toxics Rule modeling, whereas switching the boiler to gas-fired generation would effectively reduce 100% of previous HCl emissions. Therefore, for each 100 tons of uncontrolled HCl emissions, DSI would capture 90 while C2G would increase that capture further by 10 tons, which is about an 11% increase in capture — however, the COE impact increases by 724%. For a similar comparison on mercury, ACI is assumed to capture 90% while C2G would effectively capture 100%, and this 11% increase in capture would be coupled with a 2,125% increase in that unit’s COE impact. For these reasons, EPA does not believe it is cost- effective to require beyond-the-floor emission reductions from coal-to-gas fuel switching in the Toxics Rule. 167 Date: March 14, 2011 Subject: National Emission Standards for Hazardous Air Pollutants (NESHAP) Beyond the Maximum Achievable Control Technology (MACT) Floor Analysis for Coal- and Oil-fired Electric Utility Steam Generating EGUs From: Shelly Johnson, Stephen Boone To: Bill Maxwell OAQPS/SPPD/ESG (D243-01) U.S. Environmental Protection Agency Research Triangle Park, NC 27711 Introduction The purpose of this memorandum is to present the data and methodology used and the results of a beyond-the-floor (BTF) option analysis for the NESHAP source category “Coal- and Oil-fired Electric Utility Steam Generating Units” (referred to in this memorandum as “EGUs’”). For the MACT floor analysis, the EPA defined five EGU subcategories. This memorandum presents the estimates of the incremental pollutant emission reduction and cost that would be achieved by implementing a BTF option to control mercury (Hg) emissions from existing sources in the MACT Analysis Subcategory 2. Subcategory 2 is defined to include new and existing EGUs designed to burn a virgin nonagglomerating coal having a calorific value (determined on moisture and mineral matter-free basis) of less than 8,300 Btw/lb in an EGU with a furnace height-to-depth ratio of 3.82 or greater. The Hg emissions limit established as the MACT Floor 168 for Subcategory 2 is 11.0 pounds Hg per trillion British thermal EGUs (lbs/TBtu). The MACT floor analysis uses data collected in a nationwide survey of EGU owners and operators conducted by EPA in 2010 under the Information Collection Request For National Emission Standards For Hazardous Air Pollutants (NESHAP) for Coal- And Ojil-Fired Electric Utility Steam Generating Units (OMB Control No. 2060-0631). Individual EGU operating and air emissions data reported by respondents to the Information Collection Request (ICR) were compiled into a Microsoft Access software data base that serves as the data set used for this BTF option analysis (referred to in this memorandum as the “ICR data set”). BTF Option Emission Limit Selection The EPA selected a limit of 4.0 lbs Hg/TBtu for the BTF option. This Hg limit is equivalent to the level of emissions required under CAAA Section 112(d)(3) for mew or reconstructed Subcategory 2 units. Hg emissions data compiled from the ICR data set indicates that this BTF option limit is equivalent to the emission level achieved in practice (including emissions variability) by the best controlled similar source. The best controlled unit in Subcategory 2 is equipped with activated carbon injection (ACID and a fabric filter (FF). This cost analysis assumes that all units within this subcategory will require capital investments in fabric filters that are attributable to the proposed MACT standard for PM (as a surrogate for non- Hg metallic HAP). This analysis determines the marginal capital costs attributable to the BTF 169 option requiring installation of ACI systems to reduce Hg emissions to 4.0 lbs per trillion Btu. BTF Option Analysis Methodology All data used to estimate the costs that would be incurred by the thirty EGUs within Subcategory 2 came from the data obtained from the ICR data set. The data were analyzed in the following steps: Step 1 — Estimated current actual annual Hg emission rates for each existing EGU in Subcategory 2. Subsequently, the annual emissions reductions necessary to achieve the MACT floor Hg emissions limit and the BTF option Hg emissions limit were calculated for each of these EGUs. Step 2 — Identified the Hg emissions control technologies already in place for each EGU using the ICR data set. Step 3 — Determined annualized capital and operating costs for ACI controls from the ICR data set. Step 4 — Evaluated the ACI control components that would need to be added to each EGU to meet the MACT floor Hg emission limit. _ Step 5 — Evaluated the additional ACI control components that would need to be added to each EGU to meet the BTF option Hg emission limit. Step 6 — Calculated the incremental difference between the total Hg emissions reduction and 170 control cost for all existing EGUs in the subcategory to achieve the BTF option Hg emissions limit compared to the MACT floor Hg emissions limit. BTF Option Hg Emissions Estimates In order to determine the emissions reductions from the EGUs in Subcategory 2, each EGU’s current annual Hg emissions were compared to the EGU’s emissions at the MACT floor level and at the BTF option level. For each EGU, an emission factor (lb Hg/TBtu) was assigned based on EGU-specific stack test data from the ICR or from stack test data from the most similar EGU(s). The emission factor assigned to each EGU was either the EGU’s provided emission factor or an estimate of the EGU’s emission factor based on the fuel fired, the boiler type and the boiler’s control scheme. This emission factor was used to calculate the EGU’s actual annual pounds of Hg emissions. The calculation also included the EGU’s heat input capacity (MMBtwhr) and the EGU’s average capacity factor for the last 3 years. Once each EGU’s current annual Hg emissions were calculated, the annual Hg emission levels at the MACT floor and BTF option were calculated for each EGU based on the same EGU specific data. Subsequently, the annual Hg reductions between current rates and MACT floor were calculated and those between the MACT floor and the BTF option were calculated. For this analysis it is assumed that an ACI control system consists of the use of the activated carbon injectors and delivery system in conjunction 171 with a fabric filter (FF). The analysis assumed that if the EGU has other particulate matter (PM) controls in place (i.e. a coldside electrostatic precipitator) a new FF would need to be installed at the facility to comply with the non-Hg metallic HAP standard for PM. Therefore, each EGU was evaluated to determine if the EGU had ACI or FF controls. The Hg emissions control scenarios of importance for this analysis were as follows: 1. EGU with ACI and FF (ACI + FF) 2. EGU with ACI (ACI 3. EGU with FF (FF) 4. EGU with neither control (none) Each EGU within Subcategory 2 was classified into one of the four Hg emissions control scenarios. The necessary installation of additional controls for an EGU was dependent on the EGU’s current Hg emissions and the current controls. For EGUs already equipped with ACI + FF, no additional capital costs for controls were included in the cost estimate, and the cost of any additional Hg removal necessary to meet the Hg MACT floor or the BTF option was calculated based on additional ACI operating costs. For the EGUs currently with only ACI, FF installation and operating costs were attributed to the MACT floor for non-Hg metallic HAP and the BTF option costs were also calculated based on additional ACI operating costs. For EGUs currently equipped only with FF, ACI capital and operating costs were included in the cost estimate for each MACT emissions level. Similarly, the cost BTF 172 option cost estimate for EGUs currently with neither control included ACI capital and operating costs with the cost of the FF attributed to the non-Hg metallic HAP MACT standard. BTF Option Control Cost Estimates The ACI control cost values were calculated from cost information (provided by facilities currently operating ACI systems) in the EGU ICR data set. In order to calculate the cost of the BTF option, an operating cost was determined based on the amount of Hg removed, and a capital cost based on EGU size was determined. Overall, the ICR data set contains 122 EGUs for which any cost data on ACI controls were reported. These EGUs were filtered to include a total of 16 EGUs that provided capital and operating costs and sufficient Hg emissions data to determine the Hg removal attributable to the project. Of these 16 EGUs, only one EGU was within the Subcategory 2. For this analysis, all 16 EGUs were used to determine capital costs. It was assumed that the capital cost for each control system was independent of the amount of Hg removed. Each of these capital costs was determined on a heat-input-capacity basis to take into account the equipment for larger EGUs and controls being more costly. Each EGU’s control system capital cost was converted from the reported base year dollars to July 2010 dollars using the applicable Chemical Engineering Plant Cost Index (CEPCD) factors. Then, each cost was annualized by applying the capital recovery factor (CRF). The assumed interest rate was 7% and the assumed 173 period was 20 years. The CRF value used for the analysis is presented in Table 1. The remaining capital cost value applied was annualized dollars per heat-inputcapacity in million British thermal units per hour ($/MMBtu/hr). The values for each EGU’s cost were averaged for the control scenario. Since no EGU provided capital cost data for a FF only, the capital cost for an ACI was subtracted from the capital cost for an ACI and FF. The operating cost was determined solely from the lignite facility. Since the initial Hg content differs greatly between lignite and subbituminous fuels and the operating cost is based on Hg removed, it was not assumed that the data from the two fuel types could be integrated. The operating cost was calculated on a basis of pounds of Hg removed. This was calculated using the final emission factor achieved and the percent reduction. The amount of Hg removed was calculated taking into account the EGU’s capacity factor and heat input. Then, the operating cost, which was provided on an annual basis, was converted to July 2010 dollar values using the CEPCI factors. To calculate cost per pound of Hg removed, the annual operating cost was divided by the pounds of Hg removed ($/lb Hg removed) reflecting the differences between the current Hg emission rate and the MACT floor. BTF Option Analysis In order to determine the marginal costs and impacts for the BTF option Hg emissions limit, a cost was first calculated for the subcategory to achieve the MACT floor level. Then, an incremental cost was 174 calculated for the subcategory to reduce emissions from the MACT floor level to the BTF option limit. If any EGU did not meet the MACT floor, the capital cost for the installation of any control equipment the EGU did not already have was associated with reaching MACT floor. In addition, the operating costs to get the EGU from the current emission rate to the MACT floor was multiplied by the additional pounds of Hg to be removed. For the marginal cost to get to the BTF limit, the EGU was assumed to have all controls necessary for the EGU to achieve the MACT. For example, if an EGU was above the MACT floor and had to install ACI to meet the Hg MACT floor, then for the BTF Hg option, only ACI operating costs (to reduce emissions from the Hg MACT floor to the BTF limit) would be considered. However, if an EGU with just a FF met the MACT floor, but not the BTF option limit, the methodology assumed that the EGU would have to incur costs to install ACI and the operating costs to reach the BTF option limit. The current controls and additional controls for MACT and BTF are displayed on Table 5. Using this methodology, the unit-specific analyses were completed to determine additional controls and operating measures, Hg emission reductions, and the associated capital and operating costs. The estimated cost for each EGU was determined, and then the Hg reductions and total costs were summed for MACT and the increment to the BTF limit. 175 The capital costs are summarized in Table 2. The annualized capital cost for an ACI system was $108 per MMBtuv/hr of heat input capacity. The annualized operating cost was determined to be $14,867 per pound of Hg removed, as shown in Table 3. The specific EGU costs for MACT floor and the BTF option are shown in Table 5. Of the 30 EGUs, all units met the MACT floor emission level. Of the 30 EGUs, two EGUs would meet the BTF option lhmit without any additional controls. Taking into account the controls to be added to the EGUs for MACT compliance, 18 EGUs are expected to add FF to comply with the non-Hg metallic HAP standard, 20 EGUs are expected to add ACI, and 3 EGUs are expected to incur increased operating costs associated with the additional! activated carbon usage required to achieve the BTF limit. Energy impacts on Subcategory 2 due to increased auxiliary loads on induced draft (ID) fans and other electrical loads associated with installation of the fabric filter are attributed to the non-Hg metallic HAP standard. The total energy costs for Subcategory 2 were estimated based solely on the relatively low auxiliary loads from activated carbon injection systems and the associated cost data for nominally rated 500 MW units using EPA’s Coal Utility Environmental Cost (CUECost) Model for sorbent injection. The total annual costs of energy usage for operation of ACI were estimated as $2,300 per year. 176 Non-air quality environmental impacts were estimated based on the requirement to dispose of spent activated carbon in landfills. The analysis assumed that this material could be disposed of with the combustion by products as non-hazardous waste. The cost per ton of carbon disposed was estimated at $2/ton based on information in the CueCost Model, and the carbon usage per mass of Hg removed was estimated based on information published by the Center for Air Toxic Metals at the University of North Dakota Energy & Environmental Research Center (EERC). The total costs of the non-air environmental impacts for Subcategory 2 were estimated as $12,000. Non-air quality health impacts were evaluated, but no incremental health impacts were attributable to installation of fabric filters and ACI, because these technologies do not expose electric utility employees or the public to any additional health risks above the risks attributable to current utility operations involving compressed air systems, confined spaces, and exposure to fly ash. The overall additional costs for the BTF option for Subcategory 2 are shown in Table 6. For the subcategory to reach MACT, no additional costs are incurred as the data displays that each unit currently meets the MACT floor. For the existing EGUs in Subcategory 2 to implement the BTF option, the additional annual cost was estimated at an additional $70,186,000 and an additional 4,040 Ib/year of Hg is removed or $17,375 per lb of Hg removed. 177 Table 1: Capital Recovery Factor 0.07 interest rate 20 ear period CRF= 0. 0944 Equation 1: Capital Recovery Factor CRF =i * (1 +i)» =0.0944 (1 +i)? 1 Table 2: Annualized Capital Cost $/(MMBtu/hr) per ACI 108 ACI + FF 3,771 FF 3,663 Table 3: Annualized Operating Cost $1b Hg removed per r year | Operating 14, 867] Table 4: Itemized Operating Costs Energy costs 27 $/(MMBtw/hr) per Non-air environmental and health costs 4,000 $/ton Hg removed messy —-§ Sere? rut $ wo a a Tad) 1 206 CosTw'E = -§ STMT | $ a0 ij) uu) ou Cael T3AS — L-ws E819 suite S$ SEER ov $ a0 ii] 3uCu) ou we it Rwi 7 08 sty = -§ BELLE ov $ wo ti ij} uu a Twn 1 0608 aSvesr —§ SEES? ov $ 0 43} UCU ou a) PEG mre? = § SHEET ov $ wo a a ou % = ORE 1 wer arate =f | cv $ wo | ii) tutu ou saa Cig Tate mit «6S tl oY $ oo | i“) au wage 1 Wie mts = SU cv $ 000 | ij] a0 ee ee aloe eet = $ (6 UL | a] $00 | ij] ou oul um 18 alone PES SWS cy $ wo i" dij = au0u cu wi 1 IN| CNN PR ots Simewe Ov $ wo | du} aU cu we eC ta) WA ae oowsc’S = $e we oy - $ wo ry ou wae we WO) Tespe IS LOumnt $6 Ov $ we | x wae 6 20D 2OO-¥W S055 SHSTST—-§ OW LOL ov $ wo wed ri cu a ee TOO WOO-WW Gc0Ks gsswet ¢ ZT UK Ov foo 0tiéi a] eu sale Wis oo teers mr =f GUE Ov $ wo aucs Pry Gu er wm ORGe mic = Dy $ 00 avou 44| ou sae UT IN Oka wea = § WUT ov $ wo audy rr) ou CC TWUNSAY) = 28/6608 ssrord = S TH cy § wo auou ij Sahin 29 TWnSAY —Tal6aWe wie = SS asa DU BuQuiado $ wo avou} 44+ DV ae; 1) BS LS $ wo A i acu $ wo woul 44+ CV sal Saleen ws) WLS $ 0 aca $ 00 a a a ee 250 710819 $ 0 1 aud soo wou] ety Sa) ae use HC, Logg UsRIT —-§ STEN weedy Rye eco’ $ oo wou} + OY cu set OU 2 Be $ wo | woul $ wo oy sali wim (Oth aS $ ovo we $ java | oy aS CAMS $00 are $ wo u] OW a a t} aM $ ono auou $0 i Ov saa sam te Tene $ 00 acu ~ $ joo | a. wae (8) taean9 Ws yg) vOQIN pL AS Aq) 'vompepay, = pappe | ogee Yul) OY Ope ear og PRONE) cayman AORN |mAQI ON) UAL uERAIA CROW hyped WHAM) UORIORIHOD A 208 AuIDRs DIRPURS LIVIN 100); 2H 9 puodkng POPPY TOQUE) 20014 LWIN BH 20 Rina By v0W wait) sayewysy syoedmy uondG 41g $994 7 UUosajeoqns sg ajquy BLI SLE‘LI $ peaouwles By jo q] sed 4800 Surzeiedo pus [eyideo pezijenuue [wj0] GEL*SBT‘OLS 14/$ ‘HT TL 105 8800 Buryesedo puw [vrdwo [e30 1 Ole'ZI$ a4 /$ ‘18303 UT pepnfout 83800 YI[BaY PUB [RIVaMIUOMAUS ITB-UON 00€'Z$ 1A/ ‘1809 1830} UT papnyouT 83809 AZ10Uy Ov0'> IA/Q] “IW ALA J0j suoyonpas Amnosau [BUOTHTPpY (BZures9dg + [e31de) #380°) pezijenuuy [#30] 100/,J-24}-puokog wondgO ALA 10j seywuryysy 380°) pu¥ uOo}jONpey suOolss}urg By [wiaeuasoU] Z A1oBazwoQgns 9g aque 6LI 180 NMA - The American Resource THE NATIONAL MINING ASSOCIATION’S COMMENTS ON EPA’S PROPOSED NATIONAL EMISSIONS 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 76 Federal Register 24,976 (May 3, 2011) Docket ID Numbers: EPA-HQ-OAR-2009-0234 (NESHAP action) and EPA-HQ-OAR-2011-0044 (NSPS) x* ‘ABO[OUYIGZ [023U0D I[QULA B PI S9FBU [GQ] JO 8O@]jo apts [BJUaUTUONAUA paqUBmMUN puUB ADBIYJ2 BY} GIO fl uTUILEZep 07 JutQsez punNois-ayqi-uO [wNQOe GIL UOIJdUINSSB [BOLO sty} aUTWIEXVEI 01 SpaeU Wqq (TL0Z “€ ABQ) 9L0'9% Ud 9L :20mM0g | | [81 06L'ts lesctts| — so'zs 40L'6S TVLOL g19'T 196"" 901 o19'T WOA eze 1ze'l UL 0g2't WOd 6r8'lS LEP’ 806'T$ 6L9'9$ 3809 yerides (a + Ga 43g 30 TSM 179800 *.Wda TVLOL | 8423114 M4qeq | St9qqniog | jueuOduI0| 380; Gd + apd #3809 S19}UsUIMIOD : ($ wor |W ‘83809 enuuy) SPlABPUBIS SBD ploy pesodorg YI1H AjdusoD 07 83809 1gONeY payefo1g z 198 [9z e3eq) 182 3. Many analysts have predicted higher amounts of early coal retirements EPA’s claim of “common-sense” rulemaking is, in large part, intertwined with its DSI assumption. If EPA’s unsupported assumption as to the number of units that can install DSI as a compliance strategy is wrong, the costs of complying with the acid gas standard could potentially triple, as many more units will have to install or upgrade costly scrubbing technology. This increased cost will correspondingly result in more retirements and higher electricity prices as many units will not be able to absorb the additional cost. This fact invites legitimate criticism of the agency 10 GW retirement figure. For example, and in addition to the below chart,5§ FBR Capital Markets states that “...the practical applicability of DSI remains a debatable point due to the additional ash produced, reliability of the reagent supply chain, lack of utility sector experience with this technology, and the potential impact of dispatch. More limited adoption of this technology could lift the retirement number above 50 GW.” 59 68 It is important to note that each projection employed a different set of assumptions to arrive at the retirement projection — i.e. some studies analyzed the proposed rule in isolation, while others like NERA analyzed the instant rule in conjunction with other related CAA rules. The chart highlights EPA's glaring need to provide a cumulative cost estimate of all of these rules. 58 FBR Capital Markets, Mar. 25, 2011; see also Dan Eggers, “Implications of EPA Policy,” Credit Suisse, April 26, 2011 (estimating that retirements could be as high as 100 GW)(emphasis added). 183 Table 3 Summary of Coal-Fired Retirement Projections™ Analyst Date of /Retirement Publication | Projection (GW) U.S. Energy Information jApril 2011 45-73 Administration (EIA) INNERA Economic May 2011 48 iConsulting iFBR Capital Markets March 2011 35-45 McIlvaine Company March 2011 31-68 Edison Electric Institute ' anuary 2011 50 EED (The Brattle Group November 50-66 2010 North American Electric ber 2010 33-77 Reliability Corporation (NERC) ICF International (October 2010 75 Credit Suisse September 69 2010 6© Each individual analysis is filed contemporaneously with these comments (Attachment 7). 184 Even using EPA’s own data it is entirely plausible that 50 GW will be forced to reitre based on this suite of rules. The agency's 9.9 GW retirement figure is based on forecasting the Utility MACT rule in isolation, rather than examining the agency’s own base case of 25 GW gross retirements. EPA's base case estimates 299 GW of coal generation in 2015, which is an 18 GW decline in coal capacity from 2010 based on the implementation of CSAPR and Utility MACT. The base case also assumes, albeit optimistically given the inability to construct new coal plants with the stringent new source standards, an additional 7 GW in coal additions during this time. However, this entire projection is built upon full market penetration of DSI or 56 GW. Even assuming optimistically that the development of DSI is even half the forecasted rate, which is reasonable given that half of the units targeted for DSI deployment operate without scrubbers and burn medium or high sulfur coal, the retirement number could easily jump to 50 GW. Nowhere in the record does EPA engage in this sort of analytical rigor. Rather, the agency simply assumes the best without any factual support resulting in a flawed rule with an inaccurate assessment of the true impacts. 4. EPA’s mistake beliefs about the current fleet retirements The issue of flawed retirement projections is not confined to the DSI assumption. Another aspect of this issue stems from Administrator Jackson's faulty 185 statements regarding the state of the current fleet. In the proposed rule, EPA **z* 186 Connecticut Department of ENERGY & ENVIRONMENTAL PROTECTION Daniel C. Esty, Commissioner July 12, 2011 Assistant Administrator Gina A. McCarthy USEPA Headquarters Ariel Rios Building 1200 Pennsylvania Avenue, N. W. Mail Code: 6101A Washington, DC 20460 Docket ID No. EPA-HQ-OAR-2009-0234 Re: Connecticut Department of Energy and Environmental Protection Comments on the Proposed Utility Air Toxics Rule Dear Assistant Administrator McCarthy: Thank you for taking time out of your busy schedule to speak with me and the other OTC commissioners at our annual meeting in June. I am very pleased by the ambitious air pollution control agenda that you are prepared to advance in the coming months, which is why I am writing to you personally to express my support for EPA’s proposed National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units (76 FR 24976; May 3, 2011). The proposal takes important steps to protect all Americans from the toxic air emissions associated with electricity generation, giving us cleaner air and facilitating a shift to more efficient, modem methods 187 of electricity generation, including modem coal-fired generation. As you are well aware, Connecticut’s geography makes us particularly vulnerable to emissions from the large electric generating units in the West and South. As you know, we have been quite unhappy with the ongoing pollution impacts of these plants on our citizens "We are therefore pleased to see strong national rules that will put those plants, many of which are older, coal-fired generating units, on an equal environmental regulatory footing with Connecticut's electric generators, many of which are clean, natural gas-fired plants and subject to some of the strictest emissions standards in the country. We are also pleased with the release of the Cross State Air Pollution Rule this week and look forward to your proposal of Transport Rule 2 later this year in hopes that these rules will take further decisive action to level the regulatory playing field. I am also aware of the delicate task before you as you scrutinize the cumulative impact of these regulations on the electric generation sector. To assist your efforts, my technical staff has made recommendations to make the proposal and its implementation even better, and these suggestions are included as an attachment hereto. As the Connecticut Department of Environmental Protection recently became the Connecticut Department of Energy and _ Environmental Protection, our combined expertise is available to assist you to meet our shared air quality goals with an eye to our nation’s economic revitalization. By 188 working together, I hope that we will all be able to breathe easier. Yours truly, Daniel C. Esty Daniel C. Esty ) Commissioner DCE:mag ec: Erich Eschmann, EPA Headquarters Docket Administrator Printed on Recycled Paper 79 Elm Street, Hartford, CT 06106-5127 www.ct.gov/deep Affirmative Action/Equal Opportunity Employer 189 [Page 1) ATTACHMENT Technical Comments of the Connecticut Department of Energy and Environmental Protection on the Proposed National Emission Standards for Hazardous Air Pollutants from Coal- and Oil- Fired Electric Utility Steam Generating Units ATTACHMENT AI: Documentation for EPA Base Case v4.10_PTox, Chapter 3, Power System Operation Assumptions; TR2012 Base-case v4.10 1PM run; NEEDS Base Case v4.10_PTox, Mar2011 ATTACHMENT A2: CTDEEP Revisions to NEEDS v4.10_PTox ATTACHMENT B: 2008-2010 quarterly stack test results for mercury at Connecticut’s coal-fired EGUs ATTACHMENT OC: Peaking Unit Trading Agreements and Orders The Connecticut Department of Energy and Environmental Protection (CTDEEP, formerly known as Connecticut Department of Environmental Protection or CTDEP) appreciates the opportunity to comment on the “National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired. Electric Utility Steam Generating Units” (76 FR 24976, May 3, 2011), hereafter referred to as the “Utility NESHAP.” CTDEEP is pleased that the U.S. Environmental Protection Agency (EPA) has acted to reduce mercury and other hazardous air pollutants 190 (HAPs) from electric generating units (EGUs), but CTDEEP believes the proposal could be improved in several respects. To that end, CTDEEP has joined comments submitted in this docket by the National Association of Clean Air Agencies (NACAA) and Northeast States for Coordinated Air Use Management (NESCAUM). In addition to the comments presented by those two associations, CTDEEP offers six comments on the proposal herein. One of the six areas of comment is Connecticut- specific comments on EPA’s base case power system operating assumptions and the National Electric Energy Data System (NEEDS) database used in the EPA modeling for the NESHAP. Those details are included in Attachments Al and A2. I, MERCURY LIMITS Since 2008, Connecticut General Statute §22a-199 has limited the emissions rate of mercury from coal- fired EGUs to 0.6 Ibs/TBtu or an emissions rate equal to a ninety percent reduction of mercury from measured inlet concentrations. Several other Northeast states have adopted similar requirements. The Utility NESHAP’s mercury limits for coal-fired EGUs range from 1.0 Ib/TBtu (1.2 Ib/TBtu as referenced in EPA’s letter to Utility Air Regulatory Group on 5/18/11) to 4.0 lb/TBtu, levels significantly less stringent limits than those in the Northeast. While CTDEEP understands that the nation’s coal- fired EGUs include units much larger and using a range of technologies much broader than those in Connecticut, CTDEEP recommends that EPA establish an achievable mercury NESIAP standard demonstrated in practice. The 191 compliance history of CUo..necticut’s EGUs shows that its coal-fired units comply at levels [Page 2] below Connecticut’s 0.6 Ibs/TBtu limitation. Quarterly stack test data from 2009-2010 (and the first quarter of 2011 for one of the facilities) are provided in Attachment B. II BETTER DEFINE THE LIMITED-USE SUBCATEGORY At FR 25027, EPA indicates a willingness to include: “..a limited use-subcategory to account for liquid oil-fired units that only operate a limited amount of time per year on oil and are inoperative the remainder of the year. Such units could have specific emission limitations, reduced monitoring requirements (limited operation may preclude the ability to conduct stack testing), or be held to the same emission limitations (which could be met through fuel sampling) as other liquid oilfired units.” However, EPA does not give any details, such as specific number of hours, to describe what “limited amount of time” means, and the phrase is open to interpretation. EPA should define what constitutes a “limited amount of time” and allow for public comment when it has established a framework. The ability of sources to operate under a limited use-subcategory could significantly impact compliance costs and requirements associated with the Utility NESHAP. Also, the breadth of a limited use 192 subcategory could influence other state programs to address emissions from units that operate for limited circumstances. At page 25107 of the Utility NESHAP (40 CFR section 63.10006(s)), the opportunity to demonstrate compliance with the mercury, individual or total non- mercury HAP metals, hydrochloric acid (HCl), or hydrofluoric acid (HF) emissions limit based on fuel analysis seems broader than the liquid oil-fired limited use subcategory. If it is not EPA’s intention to allow units other than liquid oil- fired limited use units to utilize a fuel analysis compliance mechanism, EPA should clarify the language. Ill. TESTING REQUIREMENTS For states with several EGUs subject to the Utility NESHAP, workload in observing emission tests and/or reviewing emission test protocols could greatly mcrease. For example, CTDEEP estimates that implementing the testing requirements of the Utility NESHAP could increase the workload of CTDEEP’s emission testing staff by as much as 50%. The emissions testing staff ensures that testing is done in accordance with EPA methods. Given state resource constraints, additional staff would need to be taken from other duties to perform testing functions. Testing without adequate quality monitoring does not necessarily support compliance determinations. CTDEEP recommends that EPA consider revising the applicable monthly and bimonthly testing requirements in Section 63.10006 to quarterly testing requirements in order to provide a reasonable window of time 193 for sources and states to maintain quality testing and review procedures. It is not clear that the language at FR25107 (section 63.10006(p)) applies to low-emitting EGUs, and it is difficult to understand how the timing set out in section 63.10006(0) follows in section 63.10006(p). For example, it is unclear what the term “continue to meet” in section 63.10006(p) 194 DHEC Promote Protect Prosper C. Earl Hunter, Commissioner Promoting and protecting the health of the public and the environment BOARD: BOARD: Allen Amsler Kenyon Wells Chairman L. Clarence Batts, Jr. Mark S. Lutz Vice Chairman Ann B. Kirol, DDS Steven G. Kisner John O. Hutto, Sr., MD Secretary SOUTH CAROLINA DEPARTMENT OF HEALTH AND ENVIRONMENTAL CONTROL 2600 Bull Street » Columbia, SC 29201° Phone:(803)898-3432 * www.scdhec.gov July 20, 2011 United States Environmental Protection Agency EPA Docket Center, EPA West (Air Docket) Air and Radiation Docket, Mail Code 2822T 1200 Pennsylvania Avenue, N.W. Washington, DC 20460 Attention: Docket ID No. EPA-HQ-OAR-2009-0234 Re: Federal RegisterNol. 76, No. 85/Tuesday, May 3, 2011/Proposed Rules. National Emission Standards for Hazardous Air Pollutants From Coal and Oil-Fired Electric Utility Steam 195 Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small IndustrialCommercial- Institutional Steam Generating Units To Whom It May Concern: Thank you for the opportunity to provide comments on the proposed rule entitled National Emission Standards for Hazardous’ Aijir _ Pollutants [NESHAP]for Coal- and Oil-fired Electric Utility Steam Generating Units and Standards of Performance [NSPS/for Fossil-Fuel-Fired Electric Utility, Industrial Commercial-Institutional, and Small Industrial-Commerciallnstitutional Steam Generating Units.! The South Carolina Department of Health and Environmental Control (DHEC) is the public health and environmental agency for the State of South Carolina, and we are committed to promoting and protecting the health of the public and the environment for the State of South Carolina. This letter provides comments only on the NESHAP part of the proposed rule, commonly referred to as the “Utility MACT.”2 DHEC generally supports actions taken by the United States Environmental Protection Agency (EPA) to address the hazardous air pollutants that the Utility MACT would regulate, but DHEC has technical concerns about the proposal. Furthermore, DHEC is concerned with the 1 76 Fed. Reg. 24976 (May 3, 2011). 2 “MACT” refers to the maximum achievable control technology for utilities that the proposed NESHAP would require. 196 implementation of certain portions of the proposed Utility MACT as written. The EPA has delegated authority to implement NESHAPs to many states, including South Carolina, and we request that the EPA take into consideration the additional burden the Utility MACT and other recently promulgated rules (e.g. the Boiler MACT) pose to states’ already strained resources. DHEC asks the EPA to develop a rule that not only reduces air pollution but provides for efficient implementation and enforcement by the delegated authorities. Mercury is one of the hazardous air pollutants that the Utility MACT would regulate. The cumulative contribution of past and present mercury emissions from local, regional, and global sources affects South Carolina. DHEC is taking action to address mercury through the South Carolina Mercury Assessment and Reduction Initiative.2 This initiative is a cooperative effort to identify ways that the public, interested groups, industry, and government can address mercury in the environment. The initiative relies in part on the EPA to meet its obligations under the Clean Air Act (CAA) to promulgate lawful standards to address mercury. The following are comments that DHEC would like for the EPA to consider before promulgation of the final Utility MACT. We offer comments on emissions averaging, the relationship between the Utility MACT and other NESHAPs, performance testing, definitions, and tables. Finally, we note possible hec,gov/envi ; DJ i WWW .E 1e ° : men -lebee ive, htm (Last visited May 12, 2011). . AU . 197 typographical errors. If there are significant changes to this proposed rule, we believe the EPA should provide appropriate process and time to comment on the changes. ragin The EPA proposes to require facilities choosing to demonstrate compliance by the emission averaging option to submit an “implementation plan” for review and approval by the delegated authority. However, the EPA did not provide a clear process for implementing and enforcing this complex compliance option. We strongly request that the EPA eliminate the requirement for delegated authorities to approve implementation plans and instead develop an emission averaging certification mechanism within the Notice of Compliance Status (NOCS). The NOCS process is established, and states have experience implementing it. The EPA included an emission averaging compliance option in the Boiler MACT. DHEC comments that the EPA should be consistent in applying the emission averaging compliance option for the Boiler and Utility MACTs. a) Emission Caps For Existing Affected Sources Choosing To Demonstrate Compliance By The Emission Averaging Option Cannot Be Effectively Implemented Or Enforced. The Emission Cap Should Be Included In The Compliance Calculations. We believe that the requirement to establish an emission cap and submit an implementation plan to 198 the permitting agencies for approval is problematic as written. Because the emission cap is not used in the initial compliance demonstration or in demonstrating continuous compliance with the emission averaging option, it 1s of little use. If the intent of this option is for facilities to not exceed the cap at any time, then the EPA should include a demonstration methodology that shows that a facility is not exceeding the cap in the compliance equations in section 63.10009. If the cap is included in the compliance equations, facilities could certify compliance with the cap in the NOCS and within each required semiannual report. Additionally, if the initial and continuous compliance measures include the emission cap, the implementation plan will not be necessary and states will not have to spend valuable time and resources to approve these duplicative plans, DHEC received several implementation plans from facilities trying to comply with the vacated Boiler MACT in 2007. We encountered many problems with the approval process and received little help and guidance from the EPA. The EPA proposed the same approval process in the Utility MACT, disregarding the known problems states faced in 2007 trying to implement the emission averaging compliance option in the vacated Boiler MACT. b) Requirement For Delegated Agencies To Approve Implementation Plans Is Burdensome And Unnecessary. The EPA Should Provide Specific Guidance And Examples On What Constitutes An Acceptable Emission Cap. 199 As stated above, the requirement to establish an emission cap and submit an implementation plan to the permitting agencies for approval is problematic as written. DHEC noted this issue in our comments for the 2010 proposed Boiler MACT. While the EPA attempted to correct the enforceability problem related to the emission cap in the final Boiler MACT by requiring facilities to report the emission cap in the NOCS (see 40 CFR 63.7545(e)(5)(i)), and certify compliance with the cap in the compliance reports (see 40 CFR 63.7550(c)(3)), there is no guidance or clear process on what constitutes an acceptable and enforceable emission cap that delegated agencies can follow to approve the cap. If the EPA decides that the submittal and approval of implementation plans are necessary for the emission averaging compliance option, DHEC believes that the EPA should retain the authority to approve the implementation plans. c) The EPA Should Clarify Deadline To Establish Emission Caps To Demonstrate Compliance With The Emission Averaging Option For The Emission Level Or Control Technology. In section 63.1 0009(c), the emission rate achieved during the initial compliance test for the hazardous air pollutant (“HAP”) associated with an existing EGU in the averaging group must not exceed the emission level that was being achieved on [THE DATE 30 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or the control technology employed during the initia] compliance test must not be less effective for the 200 HAP being averaged than the control technology on [THE DATE 30 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER]. However, the EPA _ proposes. in _ section 63.10009(g)(2)(i) that information associated with the applicable HAP emission level or the control technology installed as of [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] be included in the required emissions averaging plan. This appears to be a contradiction in dates and the EPA should correct this in the final rule. d) There Are Errors In Performance Tests Language. In section 63.1 0009G)(2), the EPA proposes that, “If affected units from nonaffected units vent to the common stack, the units from nonaffected units must be shut down or vented to a different stack during the performance test."4 There appears to be a grammatical error in this clause: It is unclear as to how one can have “affected units from nonaffected units” (emphasis added). e) The EPA Should Clarify Requirement To Submit An Implementation Plan For Emission Averaging Compliance Option. There is a contradiction in section 63.1 0009(g)(1).5 This section mandates the submittal of an implementation plan by using the word “must.” 476 FR, at 25110. 5 Id. 201 However, section 63.10009(g) seems to indicate that submittal of the implementation plan is only necessary “upon request."° This apparent discrepancy should be corrected in the final rule to avoid confusion. f) The EPA Should Clarify Reference To Representative Operating Conditions And Maximum Norma! Operating Load. Section 63.1 0009(e) requires performance tests to be conducted at “maximum normal operating load.”’ However, section 63.10009(g)(2)(viil) requires demonstration of compliance with each of the applicable emission limit(s) to be achieved under “representative operating conditions."* The EPA needs to clarify this discrepancy and clearly define in section 63.10042 what constitutes maximum normal operating load oor _ representative operating conditions. g) The EPA Should Make Technical And Editorial Corrections. Section 63.10009(a) states “you may demonstrate compliance by emission averaging among the existing EGUs in the same subcategory, if your averaged emissions for such EGUs are equal to or less than the applicable emission limit”? (emphasis added). However, section 63.10009(e)(1) states, “You 6 Id. 7 Td. at 25108. 8 Id. at 25110 8 Td. at 25108 202 must use equation 1 ofthis section to demonstrate that the PM, HF, SOz, HCl, nonHg HAP metals, or Hg emissions from all existing units participating in the emissions averaging option do not exceed the emission limits in Table 2”!° (emphasis added). The EPA needs to use the same wording in both sections in order to avoid confusion. h) The EPA Should Clarify Equation 1. Section 63.10009(e)(1) requires a facility to use Equation 1 to demonstrate compliance with PM, HF, SO2, HCl, non-Hg HAP metals or Hg emissions, by using the emission rate as determined during the most recent performance test and the maximum rated heat input capacity. Due to the variability in reported heat input ratings for utility boilers, and there not currently being a definition in place on what maximum rated heat input capacity is, DHEC asks that the EPA addresses this in the final rule and establish a definition of what constitutes the maximum rated heat input capacity of a utility boiler. r itioni F i / Source Boiler MACT To Utility MACT And Vice Versa | The preamble discusses the following scenario: [T]here will likely be some cogeneration units that are determined to be covered under the Boiler NESHAP. Such unit may make a decision to increase/decrease the proportion 10 Td. 203 of production output being supplied to the electric utility grid, thus causing the unit to meet the EGU cogeneration criteria (i.e., greater than one-third of its potential output capacity and greater than 25 MWe). A unit subject to one of the Boiler NESHAP that increases its electricity output and meets the definition of an EGU would be subject to the proposed EGU NESHAP for the 6-month period after the unit meets the EGU definition. Assuming the unit did not meet the definition of an EGU following that initial occurrence, at the end of the 6- month period it would revert back to being subject to the Boiler NESHAP.!! The EPA solicits comment on the extent to which this situation might occur and whether the 6- month period is appropriate. There are several cogeneration units in South Carolina that could potentially follow the above-mentioned scenario. The EPA did not address the regulatory logistics on how this would be implemented. We request that the EPA provide in the final rule a clear process to demonstrate initial and continuous compliance for cogeneration units changing section 112 applicability. This process needs to provide the specific period or deadline when the cogeneration unit stops compliance with the Boiler MACT and starts complying with the Utility MACT and _ ~vice’ versa, include notification requirements when changing rules, and specify testing and NOCS deadlines. 11 Jd. at 25026. 204 In addition, the EPA should address how the “once- in-always-in” policy applies to sources subject to the Boiler MACT that become subject to the Utility MACT when the source meets the EGU cogeneration criteria. 8) Transitioning F CAA Section 112 T Section 129 And Vice Versa. The EPA solicits comment on whether they should include provisions similar to those included in the final CISWI rule!? to address units that combust different fuels at different times. Several utility boilers in South Carolina have the potential to combust materials that could be considered solid waste under the proposed RCRA definition. These are utility boilers that do not meet the exemption under CAA section 129 (g)(1)(B) for qualifying small power production facilities or qualifying cogeneration facilities. DHEC recommends the EPA include provisions similar to those included in the final CISWI rule to address units that combust different fuels at different times. 4) Performance Testing a) The EPA Should Clearly Specify Testing Conditions To Demonstrate Compliance With Emission Limits. 12 Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and Industrial Solid Waste Incineration Units, 76 Fed. Reg. 15704 (March 21, 2011). 205 In section 63.10007, the EPA proposes that affected sources conduct performance tests at the “maximum normal operating load.”!3 However, this maximum normal operating load is not defined in the proposed rule. Facilities use different fuels depending on many variables such as availability and cost. Fuels are also combusted in different proportions throughout the year. The EPA should provide a clear definition of maximum normal operating load or representative operating conditions in section 63.10042. The EPA should also clearly define how a source that utilizes more than one fuel should comply with this requirement. Having this clearly defined is necessary not only for determining compliance with the emission standards, but also for adequately approving site-specific test plans. In addition, there appears to be an inconsistency between the testing conditions specified in section 63.10007(c) and (f). While section 63.10007(c) requires facilities to conduct performance tests at the “maximum normal operating load,”'* section 63.10007(f) requires facilities to conduct performance tests under such condition [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385016_0333%3A09. Public record. Not legal advice.