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CHAPTER 1

INTRODUCTION AND BACKGROUND

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 electricity 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 oilfired EGUs under CAA section 112 was appropriate and necessary, in accordance with CAA 

section 112(n)(1)(A). EPA 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 years 

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 oilfired 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, by issuing a de-listing rule (Section 112(n) Revision Rule; 70 FR 15994; 
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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 

removal 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 parties

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(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 the 

Department of Justice (DOJ) that the Government’s appeals be withdrawn.

On December 18, 2008, several environmental and public health organizations 

(“Plaintiffs”)

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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 

respond to the 960,000 comments received on the proposed rule. This agreement extended the 

signing deadline to December 16, 2011.

 

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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, Pennsylvania, 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, Natural Resources Council of Maine, 

Natural Resources Defense Council, Physicians for Social Responsibility, Sierra Club, The Ohio Environmental 

Council, and Waterkeeper Alliance, Inc.
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On March 16, 2011, in response to the D.C. Circuit Court’s vacatur, EPA proposed CAA 

section 112(d) NESHAP for all coal- and oil-fired 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 promote 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 New 

Source Performance 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 (SO2), and nitrogen oxides 

(NOX) 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 Petitioners alleged that EPA failed to correctly identify the best system of 

emission reductions for the amended SO2 and NOX 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 remand, EPA 

proposed it in conjunction with the NESHAP. We 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 generating 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 the 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 of 
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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 public 

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?

The 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 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 year, the unit is considered to be coal-fired under 

this final rule. If a unit is not a coal-fired unit and burns only oil or burns oil in combination with 

a fuel other than coal 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 year, 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 established 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:

 Units designed for not low BTU virgin coal;
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 units 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 within the 

fuel burned are emitted from coal- and oil-fired EGUs. The individual HAP include mercury, 

arsenic, cadmium, lead, and nickel, among others. EPA describes the health effects of these and 

other HAP emitted from the operation of coal- and oil-fired EGUs 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 will be installed on 

coal- and oil-fired EGUs to reduce HAP will also reduce sulfur dioxide (SO2) and particulate 

matter (PM). A wide range of human health and welfare effects are linked to the emissions of 

PM and SO2. 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 section” that 

EPA determines is achievable taking into account certain statutory factors. These are referred 

to as maximum achievable control technology or MACT standards. The MACT standards for 

existing sources must be at least as stringent as the average emissions limitation achieved by 

the best performing 12 percent of existing sources in the category (for which the Administrator 

has emissions information) or the best performing 5 sources for source categories with less 

than 30 sources. This level of minimum 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 numerical 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, affected sources have the 
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choice of complying with an emissions standard per unit of input or an output based 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 demonstrate 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 for 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

(0.020 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/TBtua

(0.040 lb/GWha)

Existing - IGCC 0.040 lb/MMBtu

(0.40 lb/MWh)

0.00050 lb/MMBtu

(0.0050 lb/MWh)

2.5 lb/TBtu

(0.030 lb/GWh)

Existing – Solid oil-derived 0.0080 lb/MMBtu

(0.090 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/MWhb

0.090 lb/MWhc

0.0020 lb/MWhd0.0030 lb/GWhd

New – Solid oil-derived 0.020 lb/MWh 0.00040 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 fuel input

lb/TBtu = pounds pollutant per trillion British thermal units fuel input

lb/MWh = pounds pollutant per megawatt-hour electric output (gross)

lb/GWh = pounds pollutant per gigawatt-hour electric output (gross)

a

Beyond-the-floor limit. The MACT floor 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 permit levels in comments received
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Table 1-2. Emission Limitations for Liquid Oil-Fired EGUs

Subcategory Filterable PM Hydrogen Chloride Hydrogen Fluoride

Existing – Liquid oil-continental 0.030 lb/MMBtu

(0.30 lb/MWh)

0.0020 lb/MMBtu

(0.010 lb/MWh)

0.00040 lb/MMBtu

(0.0040 lb/MWh)

Existing – Liquid oil-non-continental 0.030 lb/MMBtu

(0.30 lb/MWh)

0.00020 lb/MMBtu

(0.0020 lb/MWh)

0.000060 lb/MMBtu

(0.00050 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 0.00050 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: SO2 (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 finalizing 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 noncontinental).
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Table 1-3. Alternate Emission Limitations for Existing Coal- and Oil-Fired EGUs

Coal-fired EGUs IGCC

Liquid Oil

Continental Non-continental Solid Oil-derived

SO2 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)

0.000060 lb/MMBtu

(0.00050 lb/MWh)

0.00080 lb/MMBtu 

(0.0080 lb/MWh)a

0.00060 lb/MMBtu 

(0.0070 lb/MWh)a

0.000040 lb/MMBtu 

(0.6 lb/GWh)

Antimony, Sb 0.80 lb/TBtu

(0.0080 lb/GWh)

1.4 lb/TBtu

(0.0240 lb/GWh)

13 lb/TBtu

(0.20 lb/GWh)

2.2 lb/TBtu

(0.020 lb/GWh)

0.80 lb/TBtu

(0.0080 lb/GWh)

Arsenic, As 1.1 lb/TBtu

(0.020 lb/GWh)

1.5 lb/TBtu

(0.020 lb/GWh)

2.8 lb/TBtu

(0.030 lb/GWh)

4.3 lb/TBtu

(0.080 lb/GWh)

0.30 lb/TBtu

(0.0050 lb/GWh)

Beryllium, Be 0.20 lb/TBtu

(0.0020 lb/GWh)

0.10 lb/TBtu

(0.0010 lb/GWh)

0.20 lb/TBtu

(0.0020 lb/GWh)

0.60 lb/TBtu

(0.0030 lb/GWh)

0.060 lb/TBtu

(0.00060 lb/GWh)

Cadmium, Cd 0.30 lb/TBtu

(0.0030 lb/GWh)

0.20 lb/TBtu

(0.0020 lb/GWh)

0.30 lb/TBtu

(0.0020 lb/GWh)

0.30 lb/TBtu

(0.0030 lb/GWh)

0.30 lb/TBtu

(0.0040 lb/GWh)

Chromium, Cr 2.8 lb/TBtu

(0.030 lb/GWh)

2.9 lb/TBtu

(0.030 lb/GWh)

5.5 lb/TBtu

(0.060 lb/GWh)

31 lb/TBtu

(0.30 lb/GWh)

0.8 lb/TBtu

(0.020 lb/GWh)

Cobalt, Co 0.80 lb/TBtu

(0.0080 lb/GWh)

1.2 lb/TBtu

(0.020 lb/GWh)

21 lb/TBtu

(0.030 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/TBtu

(1.8 lb/GWh)

8.1 lb/TBtu

(0.080 lb/GWh)

4.9 lb/TBtu

(0.080 lb/GWh)

0.80 lb/TBtu

(0.020 lb/GWh)

Manganese, Mn 4.0 lb/TBtu

(0.050 lb/GWh)

2.5 lb/TBtu

(0.030 lb/GWh)

22 lb/TBtu

(0.30 lb/GWh)

20 lb/TBtu

(0.30 lb/GWh)

2.3 lb/TBtu

(0.040 lb/GWh)

Mercury, Hg NA NA 0.20 lb/TBtu

(0.0020 lb/GWh)

0.040 lb/TBtu 

(0.00040 lb/GWh)

NA

Nickel, Ni 3.5 lb/TBtu

(0.040 lb/GWh)

6.5 lb/TBtu

(0.070 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

(0.30 lb/GWh)

3.3 lb/TBtu

(0.040 lb/GWh)

9.8 lb/TBtu

(0.20 lb/GWh)

1.2 lb/TBtu

(0.020 lb/GWh)

NA = Not applicable

a

Includes Hg
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Table 1-4. Alternate Emission Limitations for New Coal- and Oil-Fired EGUs

Liquid Oil, lb/GWh

Coal-fired EGUs IGCC Solid Oil-Derived aContinental Non-continental

SO2 0.40 lb/MWh NA NA NA 0.40 lb/MWh

Total metals 0.060 lb/GWh 0.00040 lb/MWh 0.00020 

lb/MWhb

0.0070 

lb/MWhb

0.00060 lb/MWh

Antimony, Sb 0.0080 lb/GWh 0.020 lb/GWh 0.010 0.0080 0.0080 lb/GWh

Arsenic, As 0.0030 lb/GWh 0.020 lb/GWh 0.0030 0.060 0.0030 lb/GWh

Beryllium, Be 0.00060 lb/GWh 0.0010 lb/GWh 0.00050 0.0020 0.00060 lb/GWh

Cadmium, Cd 0.00040 lb/GWh 0.0020 lb/GWh 0.00020 0.0020 0.00070 lb/GWh 

Chromium, Cr 0.0070 lb/GWh 0.040 lb/GWh 0.020 0.020 0.0060 lb/GWh

Cobalt, Co 0.0020 lb/GWh 0.0040 lb/GWh 0.030 0.30 0.0020 lb/GWh

Lead, Pb 0.0020 lb/GWh 0.0090 lb/GWh 0.0080 0.030 0.020 lb/GWh

Mercury, Hg NA NA 0.00010 0.00040 NA

Manganese, Mn 0.0040 lb/GWh 0.020 lb/GWh 0.020 0.10 0.0070 lb/GWh 

Nickel, Ni 0.040 lb/GWh 0.070 lb/GWh 0.090 4.1 0.040 lb/GWh

Selenium, Se 0.0060 lb/GWh 0.30 lb/GWh 0.020 0.020 0.0060 lb/GWh

NA = Not applicable

a

Based on best-performing similar source

b

Includes Hg.

EPA is finalizing 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-thefloor 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 limit, 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 Cost 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 a 
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reduced annualized cost of $86.7 million. EPA also performed an analysis of beyond-the-floor 

alternatives 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 112(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 finalized 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, EPA 

considers it impracticable to reliably measure emissions from these units. 

The EGU NESHAP PM and SO2 standards for new and modified facilities are as stringent 

or more stringent than the NSPS amendments. Thus, the only impacts unique to the NSPS

amendments 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, the PM emission limit for new and reconstructed electric 

utility steam generating units is 11 nanograms per joule (ng/J) (0.0090 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 SO2 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 reduction regardless of the type of fuel burned with one exception. The SO2

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) gross 

energy output or 94 percent reduction. The SOs 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 NOX emission limit for new and reconstructed electric 

utility steam generating units is 88 ng/J (0.70 lb NOX/MWh) gross energy output regardless of 

 

3

If the NESHAP requirements were not simultaneously analyzed with the NSPS amendments, then we would 

expect that the cost and benefits of the NSPS would be small.
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the type of fuel burned in the unit with one exception. The NOX emission limit for new and 

reconstructed EGUs that burn over 75 percent coal refuse (by heat input) is 110 ng/J (0.85 

lb/MWh) gross energy output. The NOX limit for modified electric utility steam generating units 

is 140 ng/J (1.1 lb/MMBtu) heat input. As an alternate to the NOX standard, owners/operators 

of new and reconstructed EGUs may elect to comply with a combined NOX/CO standard of 140 

ng/J (1.1 lb/MWh) with one exception. The NOX/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

lb/MWh) gross energy output. Finally, owners/operators of modified EGUs may elect to comply 

with a combined NOX/CO standard of 190 ng/J (1.5 lb/MWh). Compliance with these emission 

limits 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 proposed 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 explained 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 elsewhere 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 periods 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 routine 

aspects of a source’s operations. However, by contrast, malfunction is defined as a “sudden, 

infrequent, and not reasonably preventable failure of air pollution control and monitoring 

equipment, process equipment or a process to operate in a normal or usual manner...” (40 CFR 

63.2) EPA has determined that malfunctions should not be viewed as a distinct operating mode 
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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 CO2

are consistent with application of federal rules, state rules and statutes, and other binding, 

enforceable 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 Section III.A for further detail). This approach does not significantly affect the

projections underlying the cost and benefit results presented in this RIA. The baseline 

specifications used for these analyses are described in more detail in Chapter 3, Chapter 4, and 

Chapter 5 of this RIA. The EGU and non-EGU regulatory and air quality baseline used for the cobenefits analysis is described in Appendix 5A.

The costs and co-benefits from reductions in SO2 and direct PM emissions are calculated 

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 SO2 budgets 

in CSAPR. These modifications are expected to result in small changes in the levels of SO2

emission reductions in a number of states. These changes in the baseline levels of SO2

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. These modifications have not yet 

been finalized, but EPA expects the overall impact on MATS to be low.

Mercury reductions were not remodeled between the proposal and final rule for either 

the appropriate and necessary analysis or the RIA. As a result, the analysis presented in Chapter 
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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 2016 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 $37 to 90 billion (3 percent discount rate, 2007$) or $33 to 81 billion

(7 percent discount rate, 2007$) are expected for the final rule in 2016.

As described in Chapter 5, the PM2.5-related benefits of the alternative scenarios were 

derived through a benefit per-ton approach (BPT). The BPT approach develops estimates of the 

benefits per ton of SO2 and direct PM2.5 using air quality modeling for an 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 annual 

incremental compliance costs of the rule to the power sector to be $9.6 billion in 2016 (2007$).

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 compliance costs modeled in a separate analysis for oilfired EGUs of $56 million.
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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 PM2.5, Ozone, and other benefit categories.

 Chapter 6, Employment Impacts, describes the analysis to estimate 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.

 Chapter 8, Comparison of Benefits and Costs, shows a comparison of the total

benefits to total costs of the rule.