1 - 1 **CHAPTER 1 INTRODUCTION AND BAC**  **KGROUND 1.1**  **Introduction** In this action, EPA is addressing the emissions of mercury and other hazardous air pollutants by coal - and oil -fired electricity generating units. This document presents the health and welfare benefits of the final Mercury and Air Toxics Standards and compares the benefits of this rule to the estimated costs of implementing the rule in 2016. This chapter contains background information on the rule and an outline of the chapters of this Regulatory Impact Analysis (RIA). **1 .**  **2 Background for**  **Final Mercury and Air Toxics Standards 1**  **. 2** **. 1**  **NESHAP** This action finalizes National Emission Standards for Hazardous Air Pollutants ( NESHAP ) for new and existing coal - and oil -fired electric ity generating units (EGUs) meeting the definition found in Clean Air Act ( CAA ) section 112(a)(8). EPA is promulgating these standards to meet its statutory obligation to address HAP emissions from these sources under CAA section 112(d). The final NESHAP for new and existing coal - and oil -fired EGUs will be promulgated under 40 CFR part 63, subpart UUUUU. On December 20, 2000 (65 FR 79825), EPA determined that regulation of coal - and oil fired EGUs under CAA section 112 was appropriate and necessary, in accordance with CAA section 112(n)(1)(A). E PA at the same time added coal - and oil -fired EGUs to the list of source categories requiring regulation under CAA section 112(d). The December 2000 listing triggered the deadline established by Congress in CAA section 112(c)(5) under which EPA has two yea rs from the date of listing in which to promulgate “emissions standards under section (d) of this section. ” In 2002, EPA initiated a CAA section 112(d) standard setting process for coal - and oil fired EGUs, and on January 30, 2004, proposed CAA section 112 (d) standards for mercury (Hg) emissions from coal -fired EGUs and nickel (Ni) emissions from oil -fired EGUs, and, in the alternative, proposed to remove EGUs from the CAA section 112(c) list based on a finding that it was neither appropriate nor necessary to regulate EGUs pursuant to CAA section 112. EPA never finalized the proposed CAA section 112(d) standard. The Agency finalized the CAA section 111 alternative, after taking and responding to extensive public comments on both sets of regulatory options, b y issuing a de - listing rule (Section 112(n) Revision Rule; 70 FR 15994;1 - 2

March 29, 2005) and a final rule , the Clean Air Mercury Rule ( CAMR) , establishing Hg emissions standards for coal -fired EGUs under CAA section 111 on May 18, 2005 (70 FR 28606). The re moval of EGUs from the CAA section 112 list was challenged in the United States (U.S.) Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court). Petitions for reconsideration were filed by a number of parties in summer 2005. EPA responded to the petitions with a final notice of reconsideration on June 9, 2006 (71 FR 33388). Petitions for judicial review were filed on November 29, 2006, by a number of partie s 1 (State of New Jersey, et al., v. EPA, 517 F.3d 574) . On February 8, 2008, the D.C . Circuit Court vacated the Section 112(n) Revision Rule (State of New Jersey, et al., v. EPA, 517 F.3d 574), and subsequently denied rehearing and rehearing en banc of that decision. As a part of the decision, the D.C. Circuit Court also vacated CAMR, reverting to the December 2000 regulatory determination and requiring the development of emission standards under CAA section 112(d) (MACT standards) for coal - and oil -fired EGUs. The litigation process continued until, on January 29, 2009, EPA requested of t he Department of Justice (DOJ) that the Government’ s appeals be withdrawn. On December 18, 2008, several environmental and public health organizations ( “ Plaintiffs” ) 2 filed a complaint in the D.C. District Court (Civ. No. 1:08 - cv- 02198 (RMC)) alleging that the Agency had failed to perform a nondiscretionary duty under CAA section 304(a)(2) by failing to promulgate final section 112(d) standards for HAP from coal - and oil -fired EGUs by the statutorily- mandated deadline, December 20, 2002, 2 years after such sources were listed under section 112(c). EPA settled that litigation. A Consent Decree was issued on April 15, 2010, that calls for EPA to, no later than March 16, 2011, sign for publication in the Federal Register a notice of proposed rulemaking setting forth EPA’ s proposed emission standards for coal - and oil -fired EGUs and, no later than November 16, 2011, sign for publication in the Federal Register a notice of final rulemaking. EPA and the litigants agreed to a 30 - day extension in order to fully respo nd to the 960,000 comments received on the proposed rule. This agreement extended the signing deadline to December 16, 2011. 1 Environmental Petitioners; the National Congress of American Indians and Treaty Tribes; ARIPPA; American Coal for Balanced Mercury Regulations, et al.; United Mine Workers of America; Alaska Industrial Development and Export Authority; the States of New Jersey, California, Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, New Hampshire, New Mexico, New York, Penn sylvania, Rhode Island, Vermont, and Wisconsin; and the City of Baltimore, MD . 2 American Nurses Association, Chesapeake Bay Foundation, Inc., Conservation Law Foundation, Environment America, Environmental Defense Fund, Izaak Walton League of America, Nat ural Resources Council of Maine, Natural Resources Defense Council, Physicians for Social Responsibility, Sierra Club, The Ohio Environmental Council, and Waterkeeper Alliance, Inc.1 - 3

On March 16, 2011, i n response to the D.C. Circuit Court’ s vacatur, EPA proposed CAA section 112(d) NESHAP for all coal - and oil -fi red EGUs that reflect the application of the maximum achievable control technology (MACT) consistent with the requirements of CAA sections 112(d)(2) and (3). This action finalizes that proposed rule. This final rule is intended to protect air quality and p romote public health by reducing emissions of the hazardous air pollutants (HAP) listed in CAA section 112(b). **1 .**  **2 .**  **2 NSPS**  Section 111(b)(1)(b) of the CAA requires EPA to periodically review and revise the N ew S ource P erformance Standards (NSPS) as necessary to reflect improvements in methods for reducing emissions. The NSPS for EGUs (40 CFR part 60, subpart Da) were originally promulgated on June 11, 1979 (44 FR 33580). On February 27, 2006, EPA promulgated amendments to the NSPS for particulate matter (PM) , sulfur dioxide (SO 2 ), and nitrogen oxides (NO X ) contained in the standards of performance for EGUs ( 71 FR 9866). EPA was subsequently sued by the offices of multiple states attorneys general and environmental organizations on the amendments. The Petition ers alleged that EPA failed to correctly identify the best system of emission reductions for the amended SO 2 and NO X standards. The Petitioners also claimed that it is appropriate to establish emission limits for fine particulate matter and condensable particulate matter. Based upon further examination of the record, EPA has determined that certain issues in the rule warrant further consideration. On September 4, 2009, EPA was granted a voluntary remand without vacatur of the 2006 amendments. EPA considers it appropriate to respond to the NSPS voluntary remand in conjunction with the EGU NESHAP since it allows EPA to more comprehensively consider the impact on the utility sector. Therefore, even though there was no judicial timetable to complete the NSPS rem and, EPA proposed it in conjunction with the NESHAP. W e also proposed several minor amendments, technical clarifications, and corrections to existing provisions of the fossil fuel -fired EGU and large and small industrial - commercial - institutional steam gene rating units NSPS, 40 CFR part 60, subparts D, Db, and Dc. The NSPS and amendments are being finalized along with the NESHAP in this action. The title Mercury and Air Toxics Standards (MATS) used in the remainder of this RIA refers to the combination of th e EGU NESHAP and NSPS. **1 .**  **3 Appropriate & Necessary Analyses**  In the preamble to the proposed rule, EPA confirmed the December 2000 finding that it is appropriate to regulate emissions of Hg and other HAP from EGUs because emissions of1 -4

those pollutants pose hazards to public health and the environment, and EGUs are the largest or among the largest contributors of many of those HAP. We also confirmed that it is necessary to regulate EGUs under section 112 for a variety of reasons, including that hazards to pub lic health and the environment posed by HAP emissions from EGUs remain after imposition of the requirements of the Clean Air Act. This confirmation was supported in part by several new analyses of the hazards to public health posed by both mercury and non - mercury HAP. For more information on the finding and the analyses to support them, please refer to the preamble of the final rule. **1 .**  **4 Provisions of**  **the Final Mercury and Air Toxics Standards 1**  **. 4** **.1 What Is the Source Category Regulated**  **by the Final Rule ?**  T he final MATS addresses emissions from new and existing coal - and oil -fired EGUs. In general, if an EGU burns coal (either as a primary fuel or as a supplementary fuel) or any combination of coal with another fuel where the coal accounts for more than 10 p ercent of the average annual heat input during any 3 calendar years or for more than 15 percent of the annual heat input during any one calendar year, th e unit is considered to be coal -fired under this final rule . If a unit is not a coal -fired unit and bur ns only oil or burns oil in combination with a fuel other than coal where the oil accounts for more than 10 percent of the average annual heat input during any 3 calendar years or for more than 15 percent of the annual heat input during any one calendar ye ar, the unit is considered to be oil -fired under this final rule . CAA section 112(a)(8) defines an EGU as: a fossil fuel -fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one -third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale is also an electric utility steam generating unit. This action establ ished 40 CFR part 63, subpart UUUUU, to address HAP emissions from new and existing coal - and oil -fired EGUs. EPA must determine what is the appropriate maximum achievable control technology (MACT) for those units under sections 112(d)(2) and (d)(3) of the CAA. EPA has divided coal - and oil -fired EGUs into the following subcategories:

 Unit s designed for not low BTU virgin coal ;1 - 5

 u nit s designed for low BTU virgin coal ;

 IGCC units ;

 Solid oil - derived fuel -fired units ;

 Continental liquid oil -fired units; and

 Non - continental liquid oil -fired units . **1 .**  **4 .2**  **What Are the Pollutants Regulated by the Rule?** The final NESHAP regulates emissions of HAP. Available emissions data show that several HAP that are formed during the combustion process or which are contained withi n the fuel burned are emitted from coal - and oil -fired EGUs . The individual HAP include mercury, arsenic, cadmium, lead, and nickel, among others. EPA describe s the health effects of these and other HAP emitted from the operation of coal - and oil -fired EGU s in Chapter 4 of this RIA . These HAP emissions are known to cause or contribute significantly to air pollution, which may reasonably be anticipated to endanger public health or welfare. In addition to reducing HAP, the emission control technologies that w ill be installed on coal - and oil -fired EGUs to reduce HAP will also reduce sulfur dioxide (SO 2 ) and particulate matter (PM). A wide range of human health and welfare effects are linked to the emissions of PM and SO 2 . These human health and welfare effects are discussed extensively in Chapter 5 of this RIA. **1 .**  **4 .3**  **What Are the Emissions Limits**  **?** Under section 112(d), EPA must establish emission standards for major sources that “require the maximum degree of reduction in emissions of the HAP subject to this se ction” that EPA determines is achievable taking into account certain statutory factors. These are referred to as maximum achievable control technology or MACT standards. The MACT standards for existing sources must be at least as stringent as the average emissions limitation achieved by the best performing 12 percent of existing sources in the category (for which the Administrator has emissions information) or the best performing 5 sources for source categories with less than 30 sources. This level of mi nimum stringency is referred to as the MACT floor, and EPA cannot consider cost in setting the floor. For new sources, MACT standards must be at least as stringent as the control level achieved in practice by the best controlled similar source. The nume rical emission standards that are being finalized for new and existing coal - and oil -fired EGUs units are shown in Tables 1 - 1 and 1 - 2. In some cases, a ffected sources have the1 - 6

choice of complying with an emissions standard per unit of input or an output ba sed standard, which are provided in parentheses below the input - based standard. These standards must be complied with on a 30 - day rolling average basis if using continuous monitoring. If demonstrating compliance on the basis of a stack test, units must dem onstrate compliance by conducting periodic stack tests on a quarterly basis. **Table 1 -**  **1. Emission Limitations for Coal**  **- Fired and Solid Oil**  **- Derived Fuel**  **- Fired EGUs**  **Subcategory Filterable Particulate**  **Matter Hydrogen Chloride**  **Mercury** Existing Unit designed fo r not low BTU virgin coal 0.030 lb/MMBt (0.30 lb/MWh) 0.0020 lb/MMBtu (0.020 lb/MWh) 1. 2 lb/TBtu (0.0 20 lb/GWh) Existing Unit designed for low BTU virgin coal 0.030 lb/MMBtu (0.30 lb/MWh) 0.0020 lb/MMBtu (0.020 lb/MWh) 4.0 lb/TBtu a (0.040 lb/GWh a ) Existi ng - IGCC 0.040 lb/MMBtu (0. 40 lb/MWh) 0.00050 lb/MMBtu (0.00 5 0 lb/MWh) 2.5 lb/TBtu (0.0 3 0 lb/GWh) Existing – Solid oil - derived 0.0080 lb/MMBtu (0.0 9 0 lb/MWh) 0.0050 lb/MMBtu (0.080 lb/MWh) 0.20 lb/TBtu (0.0020 lb/GWh) New unit designed for not low BTU virgin coal 0.0070 lb/MWh 0. 40 lb/GWh 0.00020 lb/GWh New unit designed for coal low BTU virgin coal 0.0070 lb/MWh 0. 40 lb/GWh 0.040 lb/GWh New – IGCC 0.070 lb/MWh b 0.090 lb/MWh c 0.00 2 0 lb/MWh d 0.0030 lb/GWh d New – Solid oil - derived 0.020 lb/MWh 0.0 0040 lb/MWh 0.0020 lb/GWh Note : In some cases, affected units may comply with either an input - based standard or an output - based standard, shown in parentheses below the input - based standard. lb/MMBtu = pounds pollutant per million British thermal units fu el input lb/TBtu = pounds pollutant per trillion British thermal units fuel input lb/MWh = pounds pollutant per megawatt - hour electric output (gross) lb/GWh = pounds pollutant per gigawatt - hour electric output (gross) a Beyond -the -flo or limit . The MACT flo or for this subcategory is 11.0 lb/TBtu (0.20 lb/GWh) b Duct burners on syngas; based on permit levels in comments received c Duct burners on natural gas; based on permit levels in comments received d Based on best - performing similar source e Based on perm it levels in comments received1 - 7

**Table 1 -**  **2. Emission Limitations for Liquid Oil**  **- Fired EGUs** 

**Subcategory Filterable PM**  **Hydrogen Chloride Hydrogen Fluoride**  Existing – Liquid oil - continental 0.0 3 0 lb/MMBtu (0. 3 0 lb/MWh) 0.00 2 0 lb/MMBtu

(0.0 1 0 lb/MWh) 0. 00040 l b/MMBtu

(0.004 0 lb/MWh) Existing – Liquid oil - non - continental 0. 0 3 0 lb/MMBtu (0. 3 0 lb/MWh) 0. 000 2 0 lb/MMBtu

(0. 00 2 0 lb/MWh) 0. 0 000 6 0 lb/MMBtu

(0.000 5 0 lb/MWh) New – Liquid oil - continental 0.070 lb/MWh 0.00040 lb/MWh 0. 00040 lb/MWh New – Liquid oil - non - continental 0.20 lb/MWh 0.0020 lb/MWh 0.00 05 0 lb/MWh Note: In some cases, affected units may comply with either an input - based standard or an output - based standard, shown in parentheses below the input - based standard. We are also finalizing alternate equivalent emission standards for certain subcategories in three areas: SO 2 (in addition to HCl), individual non - Hg metals (for PM), and total non - Hg metals (for PM). These alternate emission limitations are provided in Tables 1 - 3 and 1 -4. We are finaliz ing an alternate limitation of 1 percent moisture in the liquid oil as an alternate to the HCl and HF emission limits for both liquid oil subcategories (i.e., continental and non continental).1-8 **Table 1**  **- 3.**  **Alternate Emission Limitations for Existing Coal -**  **a nd Oil**  **- Fired EGUs** 

**Coal -** **fired EGUs IGCC**  **Liquid Oil Solid Oil**  **- derived**  **Continental Non**  **- continental**  SO 2 0.20 lb/MMBtu (1.5 lb/MWh) NA NA NA 0.30 lb/MMBtu (2.0 lb/MWh) Total non - Hg metals 0.000050 lb/MMBtu (0.00050 lb/MWh) 0.0000 6 0 lb/MMBtu (0.000 5 0 l b/MWh) 0.00080 lb/MMBt u (0.0080 lb/MWh) a 0.00060 lb/MMBtu (0.0070 lb/MWh) a 0.000040 lb/MMBtu (0.6 lb/GWh) Antimony, Sb 0. 8 0 lb/TBtu (0.00 8 0 lb/GWh) 1 .4 lb/TBtu (0.0 2 40 lb/GWh) 13 lb/TBtu (0. 2 0 lb/GWh) 2.2 lb/TBtu (0.020 lb/GWh) 0. 8 0 lb/TBtu (0.0080 lb/GW h) Arsenic, As 1.1 lb/TBtu (0.020 lb/GWh) 1. 5 lb/TBtu (0.020 lb/GWh) 2.8 lb/TBtu (0.0 3 0 lb/GWh) 4. 3 lb/TBtu (0.0 8 0 lb/GWh) 0.30 lb/TBtu (0.0050 lb/GWh) Beryllium, Be 0.20 lb/TBtu (0.0020 lb/GWh) 0. 1 0 lb/TBtu (0.00 1 0 lb/GWh) 0. 2 0 lb/TBtu (0.00 2 0 lb/GWh) 0 . 6 0 lb/TBtu (0.00 3 0 lb/GWh) 0.0 6 0 lb/TBtu (0.000 6 0 lb/GWh) Cadmium, Cd 0.30 lb/TBtu (0.0030 lb/GWh) 0.20 lb/TBtu (0.0020 lb/GWh) 0. 3 0 lb/TBtu ( 0.0020 lb/GWh) 0. 3 0 lb/TBtu (0.00 3 0 lb/GWh) 0.30 lb/TBtu (0.0040 lb/GWh) Chromium, Cr 2.8 lb/TBtu (0.030 lb/GWh ) 2.9 lb/TBtu (0.0 3 0 lb/GWh) 5.5 lb/TBtu ( 0.0 6 0 lb/GWh) 31 lb/TBtu (0. 3 0 lb/GWh) 0.8 lb/TBtu (0.020 lb/GWh) Cobalt, Co 0.80 lb/TBtu (0.0080 lb/GWh) 1.2 lb/TBtu (0.0 2 0 lb/GWh) 2 1 lb/TBtu ( 0.0 3 0 lb/GWh) 113 lb/TBtu ( 1 . 40 lb/GWh) 1.1 lb/TBtu (0.020 lb/GWh) Lead, Pb 1.2 lb/TBtu (0.020 lb/GWh) 189 lb/T Btu ( 1.8 lb/G Wh) 8.1 lb/TBtu ( 0.0 8 0 lb/GWh) 4 . 9 lb/TBtu (0.0 8 0 lb/GWh) 0.80 lb/TBtu (0.020 lb/GWh) Manganese, Mn 4.0 lb/TBtu (0.050 lb/GWh ) 2.5 lb/TBtu (0.0 3 0 lb/GWh) 2 2 lb/TBtu ( 0. 3 0 lb/GWh) 20 lb/TBtu (0.30 lb/GWh) 2.3 lb/TBtu (0.040 lb/GWh) Mercury, Hg NA NA 0. 2 0 lb/TBtu (0.00 2 0 lb/GWh) 0.040 lb/TBtu (0.000 40 lb/GWh) NA Nickel, Ni 3. 5 lb/TBtu (0.040 lb/GWh) 6.5 lb/TBtu (0.0 7 0 lb/GWh) 109 lb/TBtu ( 1.1 lb/GWh) 465 lb/MMBtu ( 4 . 1 lb/GWh) 9.0 lb/TBtu (0.2 lb/GWh ) Selenium, Se 5.0 lb/TBtu (0.060 lb/GWh) 22 lb/TBtu (0. 3 0 lb/GWh) 3.3 lb/TBtu (0.040 lb/GWh) 9.8 lb/TBtu (0. 2 0 lb/GWh) 1.2 lb/TBtu (0.020 lb/GWh) NA = Not applicable a Includes Hg1 - 9

**Table 1**  **- 4.**  **Alternate Emission Limitations for New Coal -**  **and Oil -**  **Fired EGU s**  **Liquid Oil, lb/GWh Solid**  **Oil -**  **Derived Coal**  **- fired EGUs**  **IGCC a**  **Continental Non**  **- continental**  SO 2 0.40 lb/MWh NA NA NA 0.40 lb/MWh Total metals 0.0 6 0 lb/G Wh 0.00040 lb/MWh 0.00020 lb/MWh b 0.0070

lb/MWh b 0.00060 lb/MWh Antimony, Sb 0.00 8 0 lb/GWh 0.0 2 0 lb/GWh 0.0 1 0 0.0080 0.00 8 0 lb/GWh Arsenic, As 0.00 3 0 lb/GWh 0.0 2 0 lb/GWh 0.00 3 0 0.0 6 0 0.00 3 0 lb/GWh Beryllium, Be 0.00060 lb/GWh 0.00 1 0 lb/GWh 0.000 5 0 0.00 2 0 0.000 6 0 lb/GWh Cadmium, Cd 0.00040 lb/GWh 0.00 2 0 lb/GWh 0.000 2 0 0.0020 0.00 0 70 lb/GWh Chromiu m, Cr 0.0070 lb/GWh 0.040 lb/GWh 0.020 0.020 0.0060 lb/GWh Cobalt, Co 0.00 2 0 lb/GWh 0.0040 lb/GWh 0.0 3 0 0. 3 0 0.0020 lb/GWh Lead, Pb 0.00 2 0 lb/GWh 0.00 9 0 lb/GWh 0.00 8 0 0. 0 30 0.020 lb/GWh Mercury, Hg NA NA 0.00010 0.00 040 NA Manganese, Mn 0.0040 lb/GWh 0 .020 lb/GWh 0.0 2 0 0. 1 0 0.0070 lb/GWh Nickel, Ni 0.040 lb/GWh 0.0 7 0 lb/GWh 0.0 9 0 4.1 0.040 lb/GWh Selenium, Se 0.00 6 0 lb/GWh 0.30 lb/GWh 0.0 2 0 0.020 0.00 6 0 lb/GWh NA = Not applicable a Based on best - performing similar source b Includes Hg. EPA is fina lizing a beyond -the -floor standard for Hg only of 4 . 0 lbs/trillion BTU for all existing and new units designed to burn low BTU virgin coal based on the availability of activated carbon injection (ACI) for cost - effective Hg control. When considering beyond -the floor options, EPA must consider not only the maximum degree of reduction in emissions of HAP, but must take into account costs, energy, and non - air quality health and environmental impacts when doing so. We are finalizing a beyond -the -floor standard for these units because the Agency considers the cost of incremental reductions beyond the MACT floor standard of 11 lbs/trillion BTUs to be reasonable. While the primary IPM analysis discussed in Chapter 3 requires compliance with the beyond -the -floor lim it, EPA performed a supplemental analysis at proposal that estimates the difference in impacts between regulating coal -fired units designed for lignite at the floor limit and at the beyond -the -floor limit modeled. This analysis (the IPM Beyond the Floor Co st TSD) shows that if the units were only required to meet a standard of 11 lbs/trillion BTUs, the units would emit approximately an additional 3,854 lbs at a1 - 10

reduced annualized cost of $86.7 million. EPA also performed an analysis of beyond -the -floor alte rnatives which can be found in the Beyond the MACT Floor Analysis TSD. Based on these analyses, EPA concluded that the beyond -the -floor standard achieved significant additional benefits when compared to the costs of the standard. Pursuant to CAA section 11 2(h), we are finalizing a work practice standard for organic HAP, including emissions of dioxins and furans, from all subcategories of EGU . The work practice standard being finaliz ed for these EGUs would require the implementation of an annual performance test program as described the preamble . We are finalizing work practice standards because the data confirm that the significant majority of the measured organic HAP emissions from EGUs are below the detection levels of the EPA test methods, and, as such, E PA considers it impracticable to reliably measure emissions from these units . The EGU NESHAP PM and SO 2 standards for new and modified facilities are as stringent or more stringent than the NSPS amendments. Thus, the only impacts unique to the NSPS amendm ents are those for the NOx emissions limits for new and modified facilities. In the baseline for this analysis and in compliance with MATS, no source is expected to trigger the NSPS limitations for new or modified sources. Therefore, we have concluded that there are no costs or benefits associated with the NSPS amendments that are unique to these amendments. 3 For the NSPS requirements, t he PM emission limit for new and reconstructed electric utility steam generating units is 11 nanograms per joule (ng/J) (0 . 00 9 0 pound per megawatt hour (lb/MWh)) gross energy output regardless of the type of fuel burned. The PM emission limit for modified electric utility steam generating units is unchanged at 6.4 ng/J (0.015 pound per million British thermal units (lb/MMBtu) ) heat input or 99.8 percent reduction regardless of the type of fuel burned. The SO 2 emission limit for new and reconstructed electric utility steam generating units is 130 ng/J (1.0 pound per megawatt hour (lb/MWh)) gross energy output or 97 percent redu ction regardless of the type of fuel burned with one exception. The SO 2 emission limit for new electric utility steam generating units that burn over 75 percent coal refuse (by heat input) is unchanged from the current standard of 180 ng/J (1.4 lb/MWh) gro ss energy output or 94 percent reduction. The SO s emission limit for modified EGUs that burn over 75 percent coal refuse (by heat input) on an annual basis is 190 ng/J (1.5 lb/MWh) gross energy output or 90 percent reduction. The NO X emission limit for new and reconstructed electric utility steam generating units is 88 ng/J (0.70 lb NO X/MWh) gross energy output regardless of

3 If the NESHAP requirements were not simultaneously analyzed with the NSP S amendments, then we would expect that the cost and benefits of the NSPS would be small.1 - 11

the type of fuel burned in the unit with one exception . The NO X emission limit for new and reconstructed EGUs that burn over 75 percen t coal refuse (by heat input) is 110 ng/J (0.85 lb/MWh) gross energy output. The NO X limit for modified electric utility steam generating units is 140 ng/J (1 . 1 lb/MMBtu) heat input. As an alternate to the NO X standard, owners/operators of new and reconstr ucted EGUs may elect to comply with a combined NO X/CO standard of 140 ng/J (1.1 lb/MWh) with one exception . The NO X/CO emission limit for new and reconstructed EGUs that burn over 75 percent coal refuse (by heat input) on an annual basis is 160 ng/J (1.3 l b/MWh) gross energy output. Finally, owners/operators of modified EGUs may elect to comply with a combined NO X/CO standard of 190 ng/J (1.5 lb/MWh) . Compliance with the s e emission limit s is determined on a 30 - day rolling average basis using similar testing, monitoring, and other compliance provisions in the proposed rule. **1 .4.4**  **What are the Startup, Shutdown, and Malfunction**  **Requirements?** Consistent with Sierra Club v. EPA ( 551 F.3d 1019 (DC Cir. 2008), cert. denied, 130 S. Ct. 1735 (U.S. 2010)), EPA propos ed numerical emission standards that would apply at all times, including during periods of startup, shutdown and malfunction. In this final rule, EPA has evaluated comments and other data concerning startup and shutdown periods and, for the reasons explain ed below, is establishing work practice standards for startup and shutdown periods as the terms are defined in the final rule. EPA has revised this final rule to require sources to meet a work practice standard, which requires following the manufacturer’ s recommended procedures for minimizing periods of startup and shutdown, for all subcategories of new and existing coal - and oil -fired EGUs (that would otherwise be subject to numeric emission limits) during periods of startup and shutdown. As discussed else where in the preamble, we considered whether performance testing, and therefore, enforcement of numeric emission limits, would be practicable during periods of startup and shutdown. After reviewing comments and other data regarding the nature of these peri ods of operation, the EPA is finalizing a work practice standard for periods of start up and shut down. EPA will revisit this decision during the mandatory 8 -year review cycle. Periods of startup, normal operations, and shutdown are all predictable and rou tine aspects of a source ’ s operations. However, by contrast, malfunction is defined as a “sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner... ” (40 CFR 63.2) EPA has determined that malfunctions should not be viewed as a distinct operating mode1 - 12

and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 112(d) standards, which , once promulgated, apply at all times. In the event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event, EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions . EPA would also consider whether the source ’ s failure to comply with the CAA section 112(d) standard was, in fact, “sudden, infrequent, not reasonably preventable ” and was not instead “ caused in part by poor maintenance or careless operation ” ( 40 CFR 63.2 ). **1 .5**  **Baseline and Years of Analysis** The emissions scenarios for the RIA reflect the Cross - State Air Pollution Rule (CSAPR) as finalized in July 2011 and the emissions reductions of SOx, NOx, directly emitted PM , and CO 2 are consistent with application of federal rules, state rules and statutes, and other binding, en forceable commitments in place by December 2010 for the analysis timeframe. Consistent with the mercury risk deposition modeling for MATS, EPA did not model non -federally enforceable mercury- specific emissions reduction rules in the base case or MATS policy case (see preamble S ection III.A for further detail). This approach does not significantly affect the projections underlying the cost and benefit results presented in this RIA. T he baseline specifications used for these analyses are described in more de tail in Chapter 3 , Chapter 4, and Chapter 5 of this RIA. The EGU and non - EGU regulatory and air quality baseline used for the co benefits analysis is described in Appendix 5A. The costs and co - benefits from reductions in SO 2 and direct PM emissions are cal culated using a baseline that includes the Cross State Air Pollution Rule (CSAPR; 76 FR 48208 ) finalized July 6, 2011. EPA has subsequently proposed minor modifications to the state - level SO 2 budgets in CSAPR. These modifications are expected to result in small changes in the levels of SO 2 emission reductions in a number of states. These changes in the baseline levels of SO 2 emissions may result in slightly larger reductions in emissions and, consequently, slightly higher benefits, being attributed to MATS. The impact on control costs is uncertain, but likely to be minimal given that only 1% of units are potentially affected. T hese modifications have not yet been finalized, but EPA expects the overall impact on MATS to be low. Mercury reductions were not rem odeled between the proposal and final rule for either the appropriate and necessary analysis or the RIA. As a result, the analysis presented in Chapter1 - 13

4 uses the MATS proposal baseline that includes proposed, but not final, CSAPR , as well as the mercury standards as proposed rather than as finalized . Furthermore, there were some differences in the treatment of the baseline at proposal relative to the baseline included here in that it included non -federally enforceable state rules. These differences do not have a significant impact on total mercury emissions. Mercury benefits are magnitudes smaller than the co - benefits presented here and do not impact the final rounded benefits estimates . The year 201 6 is the compliance year for MATS, though as we explain in later chapters, we use 2015 as a proxy for compliance in 2016 for our cost analysis due to availability of modeling impacts in that year. All estimates presented in this report represent annualized estimates of the benefits and costs of the final MATS in 2016 rather than the net present value of a stream of benefits and costs in these particular years of analysis. **1 .6**  **Benefits of Emission Controls** The benefits of the final MATS are discussed in Chapters 4 and 5 of this report. Annual monetized benefits of $ 37 to 9 0 billion (3 percent discount rate , 2007$ ) or $ 33 to 8 1 billion (7 percent discount rate , 2007$ ) are expected for the final rule in 2016. As described in Chapter 5, t he PM 2.5 - related benefits of the alternative scenarios were derived through a benefit per-ton ap proach (BPT). The BPT approach develops estimates of the benefits per ton of SO 2 and direct PM 2.5 using air quality modeling for a n interim policy scenario that is expected to have similar pollutant reductions as MATS along with the baseline used for the remainder of the analysis described in this RIA . These benefit per ton estimates are then multiplied by the amount of emission reductions expected from MATS as finalized to estimate the benefits of the rule. **1 .7**  **Cost of Emission Controls** EPA analyzed the costs of the final MATS using the Integrated Planning Model (IPM). EPA has used this model in the past to analyze the impacts of regulations on the power sector, including the proposed and final CSAPR and proposed MATS . EPA estimates the annua l incremental compliance costs of the rule to the power sector to be $ 9. 6 billion in 201 6 (2007 $ ) . 4 A description of the methodology used to model the costs and economic impacts to the power sector is discussed in Chapter 3 of this report. A description of how the employment impacts associated with this final rule are estimated is provided in Chapter 6 of this report.

4 This total includes compliance costs of $9.4 billion modeled in IPM for coal fired EGUs, monitoring, recordkeeping, and reporting costs of $158 million, and complia nce costs modeled in a separate analysis for oil fired EGUs of $56 million.1 - 14

**1 .8**  **Organization of the Regulatory Impact Analysis** This report presents EPA’ s analysis of the benefits, costs, and other economic effects of the final MATS to fulfill the requirements of a Regulatory Impact Analysis (RIA). This RIA includes the following chapters:

 Chapter 2 , Electric Power Sector Profile, describes the industry affected by the rule.

 Chapter 3 , Cost, Economic, and Energy Impacts, describes the modeling conducted to estimate the cost, economic, and energy impacts to the power sector.

 Chapter 4, Mercury and Other HAP Benefits Analysis, describes the methodology and results of the benefits analysis for mercury and other HAP.

 Chapter 5 , Co - Benefits Analysis, describes the methodology and results of the benefits analysis for PM 2.5, Ozone, and other benefit categories.

 Chapter 6, Employment Impacts, describes the analysis to esti mate the employment impacts associated with the final rule .

 Chapter 7 , Statutory and Executive Order Impact Analyses, describes the small business, unfunded mandates, paperwork reduction act, environmental justice, and other analyses conducted for the rule to meet statutory and Executive Order requirements.

 Chapt er 8, Comparison of Benefits and Costs, shows a comparison of the total benefits to total costs of the rule.