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DRAFT – DELIBERATIVE DOCUMENT – DO NOT CITE OR QUOTE

EO12866NESHAPMACT_NSPSforUtilitiesMATS2060_AP52Final20111216a.docx

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2009-0234; EPA-HQ-OAR-2011-0044, FRL-9286-1]

RIN 2060-AP52; RIN 2060-AR31

National Emission Standards for Hazardous Air Pollutants from 

Coal- and Oil-fired Electric Utility Steam Generating Units and 

Standards of Performance for Fossil-Fuel-Fired Electric Utility, 

Industrial-Commercial-Institutional, and Small IndustrialCommercial-Institutional Steam Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

SUMMARY: On May 3, 2011, under authority of Clean Air Act (CAA) 

sections 111 and 112, the EPA proposed both national emission 

standards for hazardous air pollutants (NESHAP) from coal- and 

oil-fired electric utility steam generating units (EGUs) and 

standards of performance for fossil-fuel-fired electric utility, 

industrial-commercial-institutional, and small industrialcommercial-institutional steam generating units (76 FR 24976). 

After consideration of public comments, the EPA is finalizing 

these rules in this action.

Pursuant to CAA section 111, the EPA is revising standards 

of performance in response to a voluntary remand of a final 
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rule. Specifically, we are amending new source performance 

standards (NSPS) after analysis of the public comments we 

received. We are also finalizing several minor amendments, 

technical clarifications, and corrections to existing NSPS 

provisions for fossil fuel-fired EGUs and large and small 

industrial-commercial-institutional steam generating units.

Pursuant to CAA section 112, the EPA is establishing NESHAP 

that will require coal- and oil-fired EGUs to meet hazardous air 

pollutant (HAP) standards reflecting the application of the 

maximum achievable control technology. This rule protects air 

quality and promotes public health by reducing emissions of the 

HAP listed in CAA section 112(b)(1).

DATES: This final rule is effective on [INSERT DATE 60 DAYS 

AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]. The 

incorporation by reference of certain publications listed in 

this rule is approved by the Director of the Federal Register as 

of [INSERT DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER].

ADDRESSES: The EPA established two dockets for this action: 

Docket ID. No. EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID 

No. EPA-HQ-OAR-2009-0234 (NESHAP action). All documents in the 

dockets are listed on the http://www.regulations.gov Web site. 

Although listed in the index, some information is not publicly 
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available, e.g., confidential business information or other 

information whose disclosure is restricted by statute. Certain 

other material, such as copyrighted material, is not placed on 

the Internet and will be publicly available only in hard copy 

form. Publicly available docket materials are available either 

electronically through http://www.regulations.gov or in hard 

copy at EPA’s Docket Center, Public Reading Room, EPA West 

Building, Room 3334, 1301 Constitution Avenue, NW, Washington, 

D.C. 20004. This Docket Facility is open from 8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding legal holidays. The 

telephone number for the Public Reading Room is (202) 566-1744, 

and the telephone number for the Air Docket is (202) 566-1741.

FOR FURTHER INFORMATION CONTACT: For the NESHAP action: Mr. 

William Maxwell, Energy Strategies Group, Sector Policies and 

Programs Division, (D243-01), Office of Air Quality Planning and 

Standards, U.S. Environmental Protection Agency, Research 

Triangle Park, North Carolina 27711; Telephone number: (919) 

541-5430; Fax number (919) 541-5450; E-mail address: 

maxwell.bill@epa.gov. For the NSPS action: Mr. Christian 

Fellner, Energy Strategies Group, Sector Policies and Programs 

Division, (D243-01), Office of Air Quality Planning and 

Standards, U.S. Environmental Protection Agency, Research 

Triangle Park, North Carolina 27711; Telephone number: (919) 
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541-4003; Fax number (919) 541-5450; E-mail address: 

fellner.christian@epa.gov. 

SUPPLEMENTARY INFORMATION:

The information presented in this preamble is organized as 

follows:

I. General Information

A. Does this action apply to me?

B. Where can I get a copy of this document?

C. Judicial Review

D. What are the costs and benefits of these final rules?

II. Background Information on the NESHAP

A. What is the statutory authority for this final NESHAP?

B. What is the litigation history of this final rule?

C. What is the relationship between this final rule and other 

combustion rules?

D. What are the health effects of pollutants emitted from coaland oil-fired EGUs?

III. Appropriate and Necessary Finding

A. Overview

B. Peer Review of the Hg Risk TSD Supporting the Appropriate and 

Necessary Finding for Coal and Oil-Fired EGUs and EPA Response

C. Summary of Results of Revised Hg Risk TSD of Risks to 

Populations with High Levels of Self-Caught Fish Consumption

D. Peer Review of the Approach for Estimating Cancer Risks 

Associated with Cr and Ni Emissions in the U.S. EGU Case Studies 

of Cancer and Non-Cancer Inhalation Risks for Non-mercury Hg HAP 

and EPA Response 

E. Summary of Results of Revised U.S. EGU Case Studies of Cancer 

and Non-Cancer Inhalation Risks for Non-mercury Hg HAP 

F. Public Comments and Responses to the Appropriate and 

Necessary Finding

G. EPA Affirms the Finding that it is Appropriate and Necessary 

to Regulate EGUs to Address Public Health and Environmental 

Hazards Associated with Emissions of Hg and Non-mercury Hg HAP 

from EGUs

IV. Denial of Delisting Petition

A. Requirements of section 112(c)(9)

B. Rationale for Denying UARG’s Delisting Petition

C. EPA’s technical analyses for the Appropriate and Necessary 

Finding provide further support for the conclusion that coalfired EGUs should remain a listed source category
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V. Summary of the Final NESHAP

A. What is the source category regulated by this final rule?

B. What is the affected source?

C. What are the pollutants regulated by this final rule?

D. What emission limits and work practice standards must I meet?

E. What are the requirements during periods of startup, 

shutdown, and malfunction?

F. What are the testing and initial compliance requirements?

G. What are the continuous compliance requirements?

H. What are the notification, recordkeeping and reporting 

requirements?

I. Submission of Emissions Test Results to the EPA

VI. Summary of Significant Changes Since Proposal

A. Applicability 

B. Subcategories

C. Emission Limits

D. Work Practice Standards for Organic HAP Emissions

E. Requirements during Startup, Shutdown, and Malfunction 

F. Testing and Initial Compliance

G. Continuous Compliance

H. Emissions Averaging

I. Notification, Recordkeeping and Reporting

J. Technical/Editorial Corrections

VII. Public Comments and Responses to the Proposed NESHAP

A. MACT Floor Analysis

B. Rationale for Subcategories

C. Surrogacy

D. Area sources

E. Health-based Emission Limits

F. Compliance Date and Reliability Issues

G. Cost and Technology Basis Issues

H. Testing and Monitoring

VIII. Background Information on the NSPS

A. What is the statutory authority for this final NSPS?

B. What is the regulatory authority for the final rule?

IX. Summary of the final NSPS

X. Summary of Significant Changes Since Proposal

XI. Public Comments and Responses to the Proposed NSPS

XII. Impacts of The Final Rule

A. What are the air impacts?

B. What are the energy impacts?

C. What are the cost impacts?

D. What are the economic impacts?

E. What are the benefits of this final rule?

XIII. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review and 
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Executive Order 13563, Improving Regulation and Regulatory 

Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act as Amended by the Small Business 

Regulatory Enforcement Fairness Act (RFA) of 1996 SBREFA), 5 

U.S.C. 601 et seq.

D. Unfunded Mandates Reform Act of 1995

E. Executive Order 13132, Federalism

F. Executive Order 13175, Consultation and Coordination with 

Indian Tribal Governments

G. Executive Order 13045, Protection of Children from 

Environmental Health Risks and Safety Risks

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

K. Congressional Review Act

I. General Information

A. Does this action apply to me?

The regulated categories and entities potentially affected 

by the final standards are shown in Table 1 of this preamble.

TABLE 1. POTENTIALLY AFFECTED REGULATED CATEGORIES AND ENTITIES

Category NAICS 

code1

Examples of potentially 

regulated entities

Industry 221112 Fossil fuel-fired electric utility 

steam generating units.

Federal 

government

2211222 Fossil fuel-fired electric utility 

steam generating units owned by the 

federal government.

State/local/

tribal

government

2211222

921150

Fossil fuel-fired electric utility 

steam generating units owned by 

states, tribes, or municipalities.

Fossil fuel-fired electric utility 

steam generating units in Indian 

country.

1 North American Industry Classification System.

2 Federal, state, or local government-owned and operated 
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establishments are classified according to the activity in which 

they are engaged.

This table is not intended to be exhaustive, but rather is 

meant to provide a guide for readers regarding entities likely 

to be affected by this action. To determine whether you, as 

owner or operator of a facility, company, business, 

organization, etc., will be regulated by this action, you should 

examine the applicability criteria in 40 CFR 60.40, 60.40Da, or 

60.40c or in 40 CFR 63.9981. If you have any questions regarding 

the applicability of this action to a particular entity, consult 

either the air permitting authority for the entity or your EPA 

regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 

(General Provisions).

B. Where can I get a copy of this document?

In addition to being available in the dockets, an 

electronic copy of this action will also be available on the 

Worldwide Web (WWW) through the Technology Transfer Network 

(TTN). Following signature by the Administrator, a copy of the 

action will be posted on the TTN’s policy and guidance page for 

newly proposed or promulgated rules at the following address: 

http://www.epa.gov/ttn/oarpg/. The TTN provides information and 

technology exchange in various areas of air pollution control.

C. Judicial Review

Under CAA section 307(b)(1), judicial review of this final 
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rule is available only by filing a petition for review in the 

U.S. Court of Appeals for the District of Columbia Circuit by 

[INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 

Under CAA section 307(d)(7)(B), only an objection to this final 

rule that was raised with reasonable specificity during the 

period for public comment (including any public hearing) can be 

raised during judicial review. This section also provides a 

mechanism for the EPA to convene a proceeding for 

reconsideration, “[i]f the person raising an objection can 

demonstrate to the Administrator that it was impracticable to 

raise such objection within [the period for public comment] or 

if the grounds for such objection arose after the period for 

public comment (but within the time specified for judicial 

review) and if such objection is of central relevance to the 

outcome of the rule[.]” Any person seeking to make such a 

demonstration to us should submit a Petition for Reconsideration 

to the Office of the Administrator, Environmental Protection 

Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., 

NW., Washington, D.C. 20004, with a copy to the person listed in 

the preceding FOR FURTHER INFORMATION CONTACT section, and the 

Associate General Counsel for the Air and Radiation Law Office, 

Office of General Counsel (Mail Code 2344A), Environmental 

Protection Agency, 1200 Pennsylvania Ave., NW, Washington, D.C.
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20004. Note, under CAA section 307(b)(2), the requirements 

established by this final rule may not be challenged separately 

in any civil or criminal proceedings brought by EPA to enforce 

these requirements.

D. What are the costs and benefits of this final rule?

Consistent with Executive Order (EO) 13563, “Improving 

Regulation and Regulatory Review,” we have estimated the costs

and benefits of the final rule. This rule will reduce emissions 

of HAP, including mercury (Hg), from the electric power 

industry. Installing the technology necessary to reduce 

emissions directly regulated by this rule will also reduce the 

emissions of directly emitted PM2.5 and sulfur dioxide (SO2), a 

PM2.5 precursor. The benefits associated with these PM and SO2

reductions are referred to as co-benefits, as these reductions 

are not the primary objective of this rule.

The EPA estimates that this final rule will yield annual 

monetized benefits (in 2007$) of between $37 to $90 billion 

using a 3 percent discount rate and $33 to $81 billion using a 7 

percent discount rate. The great majority of the estimates are 

attributable to co-benefits from reductions in PM2.5-related 

mortality. The annual social costs, approximated by the sum of 

the compliance costs and monitoring and reporting costs, are 

$9.6 billion (2007$) and the annual quantified net benefits (the 
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difference between benefits and costs) are $27 to $80 billion 

using a 3 percent discount rate or $24 to $71 billion using a 7 

percent discount rate. It is important to note that the PM2.5 cobenefits reported here contain uncertainty, due in part to the 

important assumption that all fine particles are equally potent 

in causing premature mortality and because many of the benefits 

are associated with reducing PM2.5 levels at the low end of the 

concentration distributions examined in the epidemiology studies 

from which the PM2.5-mortality relationships used in this 

analysis are derived.

The benefits of this rule outweigh costs by between 3 to 1 

or 9 to 1 depending on the benefit estimate and discount rate 

used. The co-benefits are substantially attributable to the 

4,200 to 11,000 fewer PM2.5-related premature mortalities

estimated to occur as a result of this rule. The EPA could not 

monetize some costs and important benefits, such as some Hg 

benefits and those for the HAP reduced by this final rule other 

than Hg. Upon considering these limitations and uncertainties, 

it remains clear that the benefits of this rule, referred to in 

short as the Mercury and Air Toxics Standards (MATS), are 

substantial and far outweigh the costs.

TABLE 2. SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND 

NET BENEFITS FOR THE FINAL RULE IN 2016 (BILLIONS OF 2007$)a

3% Discount Rate 7% Discount Rate
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Total Monetized 

Benefitsb

$37 to $90 $33 to $81

Partial Hg-related 

Benefitsc

$0.004 to $0.006 $0.0005 to $0.00

1

PM2.5-related Cobenefitsb$36 to $89 $33 to $80

Climate-related CoBenefitsd$0.36 $0.36

Total Social Costse $9.6 $9.6

Net Benefits $27 to $80 $24 to $71

Non-monetized Benefits Visibility in Class I areas

Other neurological effects of Hg exposure

Other health effects of Hg exposure 

Health effects of ozone and direct 

exposure to SO2 and NO2

Ecosystem effects

Health effects from commercial and nonfreshwater fish consumption

Health risks from exposure to non-mercury

HAP

a All estimates are for 2016, and are rounded to two significant 

figures. 

b The total monetized benefits reflect the human health benefits 

associated with reducing exposure to PM2.5. The reduction in 

premature fatalities each year accounts for over 90 percent of 

total monetized benefits. Benefits in this table are nationwide 

and are associated with directly emitted PM2.5 and SO2 reductions. 

The estimate of social benefits also includes CO2-related 

benefits calculated using the social cost of carbon, discussed 

further in chapter 5 of the RIA. Mercury benefits were 

calculated using the baseline from proposal. The difference in 

emissions reductions between proposal and final does not 

substantially affect the Hg benefits. 

c Based on an analysis of health effects due to recreational 

freshwater fish consumption.

d This table shows monetized CO2 co-benefits that were calculated 

using the global average social cost of carbon estimate at a 3 

percent discount rate. In section 5.6 of the Regulatory Impact 

Analysis (RIA) we also report the monetized CO2 co-benefits using 

discount rates of 5 percent, 2.5 percent, and 3 percent (95th

percentile).

e Total social costs are approximated by the compliance costs for 

both coal- and oil-fired units. This includes monitoring, 

recordkeeping, and reporting costs.
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For more information on how EPA is addressing EO 13563, see 

the EO discussion in the Statutory and Executive Order Reviews 

section of this preamble.

II. Background Information on the NESHAP

On May 3, 2011, the EPA proposed this rule to address 

emissions of toxic air pollutants from coal and oil-fired 

electric generating units as required by the CAA. The proposal 

explained at length the statutory history and requirements 

leading to this rule, the factual and legal basis for the rule 

and its specific provisions, and the costs and benefits to the 

public health and environment from the proposed requirements.

The EPA received over 900,000 comments from members of the 

public on the proposed rule, substantially more than for any 

other prior regulatory proposal. The comments express concerns 

about the presence of Hg in the environment and the effect it 

has on human health, concerns about the costs of the rule, how 

challenging it may be for some sources to comply and questions 

about the impact it may have on this country’s electricity 

supply and economy. Many comments provided additional 

information and data that have enriched the factual record and 

enabled EPA to finalize a rule that fulfills the mandate of the 

CAA while providing flexibility and compliance options to 

affected sources—options that make the rule less costly and 
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compliance more readily manageable.

This rule establishes uniform emissions-control standards 

that sources can meet with proven and available technologies and 

operational processes in a timeframe that is achievable. They 

will put this industry, now the single largest source of Hg 

emissions in the United States (U.S.) with emissions of 29 tons 

per year, on a path to reducing those emissions by approximately 

90 percent. Emissions of other toxic metals, such as arsenic 

(As) and nickel (Ni), dioxins and furans, acid gases (including 

hydrochloric acid (HCl) and SO2) will also decrease dramatically 

with the installation of pollution controls. And the 

flexibilities established in this rule along with other 

available tools provide a clear pathway to compliance without 

jeopardizing the country’s energy supply.

This preamble explains EPA’s appropriate and necessary 

finding, the elements of the final rule, key changes the EPA is 

making in response to comments submitted on the proposed rule, 

and our responses to many of the comments we received. A full 

response to comments is provided in the response to comments 

document available in the docket for this rulemaking. 

A. What is the statutory authority for this final rule?

Congress established a specific structure for determining 
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whether to regulate EGUs under CAA section 112.1 Specifically, 

Congress enacted CAA section 112(n)(1).

Section 112(n)(1)(A) of the CAA requires the EPA to conduct 

a study to evaluate the remaining public health hazards that are 

reasonably anticipated to occur as a result of EGUs’ HAP 

emissions after imposition of CAA requirements. The EPA must 

report the results of that study to Congress, and regulate EGUs 

“if the Administrator finds such regulation is appropriate and 

necessary,” after considering the results of that study. Thus, 

CAA section 112(n)(1)(A) governs how the Administrator decides 

whether to list EGUs for regulation under CAA section 112. See

New Jersey v. EPA, 517 F.3d 574 at 582 (D.C. Cir. 2008)

(“Section 112(n)(1) governs how the Administrator decides 

whether to list EGUs; it says nothing about delisting EGUs.”). 

As directed, the EPA conducted the study to evaluate the 

remaining public health hazards and reported the results to 

Congress (Utility Study Report to Congress (Utility Study)).2 We 

discuss this study below in conjunction with other studies that 

CAA section 112(n)(1)requires concerning EGUs. See also 76 FR 

24982-24984 (summarizing studies).

 

1 “Electric utility steam generating unit” is defined, in part, 

as any “fossil fuel fired combustion unit of more than 25 

megawatts that serves a generator that produces electricity for 

sale.” See CAA section 112(a)(8).

2 U.S. EPA. Study of Hazardous Air Pollutant Emissions from 

Electric Utility Steam Generating Units—Final Report to 

Congress. EPA-453/R-98-004a. February 1998.
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Once the EPA lists a source category pursuant to CAA 

section 112(c), the EPA must then establish technology-based 

emission standards under CAA section 112(d). For major sources,

the EPA must establish emission standards that “require the 

maximum degree of reduction in emissions of the hazardous air 

pollutants subject to this section” that the EPA determines are 

achievable taking into account certain statutory factors. See 

CAA section 112(d)(2). These standards 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 emission 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. See CAA section 112(d)(3)(A) and (B), respectively. 

This level of minimum stringency is referred to as the “MACT 

floor,” and the 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. See CAA section 112(d)(3).

The EPA also must consider more stringent “beyond-thefloor” control options. When considering beyond-the-floor 

options, the EPA must consider the maximum degree of reduction 
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in HAP emissions and take into account costs, energy, and nonair quality health and environmental impacts when doing so. See 

Cement Kiln Recycling Coal. v. EPA, 255 F.3d 855, 857-58 (D.C. 

Cir. 2001).

Alternatively, the EPA may set a health-based standard for 

HAP that have an established health threshold, and the standard 

must provide “an ample margin of safety.” See CAA section 

112(d)(4). As these standards could be less stringent than MACT 

standards, the Agency must have detailed information on HAP 

emissions from the subject sources and sources located near the 

subject sources before exercising its discretion to set such 

standards.

For area sources, the EPA may issue standards or 

requirements that provide for the use of generally available 

control technologies or management practices (GACT standards) in 

lieu of promulgating MACT or health-based standards. See CAA 

section 112(d)(5).

As noted above, CAA section 112(n) requires completion of 

various reports concerning EGUs. For the first report, the 

Utility Study, Congress required the EPA to evaluate the hazards 

to public health reasonably anticipated to occur as the result 

of HAP emissions from EGUs after imposition of the requirements 

of the CAA. See CAA section 112(n)(1)(A). The EPA was required 
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to report results from this study to Congress by November 15, 

1993. Id. Congress also directed the EPA to conduct “a study of 

mercury emissions from [EGUs], municipal waste combustion units, 

and other sources, including area sources” (Mercury Study). See

CAA section 112(n)(1)(B). The EPA was required to report the 

results from this study to Congress by November 15, 1994. Id. In 

conducting this Mercury Study, Congress directed the EPA to 

“consider the rate and mass of such emissions, the health and 

environmental effects of such emissions, technologies which are 

available to control such emissions, and the costs of such 

technologies.” Id. Congress directed the National Institute of 

Environmental Health Sciences (NIEHS) to conduct the last 

required evaluation, “a study to determine the threshold level 

of mercury exposure below which adverse human health effects are 

not expected to occur” (NIEHS Study). See CAA section 

112(n)(1)(C). The NIEHS was required to submit the results to 

Congress by November 15, 1993. Id. In conducting this study, 

NIEHS was to determine “a threshold for mercury concentrations 

in the tissue of fish which may be consumed (including 

consumption by sensitive populations) without adverse effects to 

public health.” Id.

In addition, Congress, in conference report language 

associated with the EPA’s fiscal year 1999 appropriations, 
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directed the EPA to fund the National Academy of Sciences (NAS) 

to perform an independent evaluation of the available data 

related to the health impacts of methylmercury (MeHg) (NAS Study 

or MeHg Study). H.R. Conf. Rep. No 105-769, at 281-282 (1998). 

Specifically, Congress required NAS to advise the EPA as to the 

appropriate reference dose (RfD) for MeHg. 65 FR 79826. The RfD 

is the amount of a chemical which, when ingested daily over a 

lifetime, is anticipated to be without adverse health effects to 

humans, including sensitive subpopulations. In the same 

conference report, Congress indicated that the EPA should not 

make the appropriate and necessary regulatory determination for 

Hg emissions until the EPA had reviewed the results of the NAS 

Study. See H.R. Conf. Rep. No 105-769, at 281-282 (1998).

As directed by Congress through different vehicles, the NAS 

Study and the NIEHS Study evaluated the same issues. The NIEHS 

completed the NIEHS Study in 1995,3 and the NAS completed the NAS 

Study in 2000.4 Because NAS completed its study 5 years after the 

NIEHS Study, and considered additional information not earlier 

available to NIEHS, for purposes of this document we discuss the 

content of the NAS Study as opposed to the NIEHS Study.

The EPA conducted the studies required by CAA section 

 

3 NIEHS Study, August 1995; EPA-HQ-OAR-2009-3053.

4 National Research Council (NAS). 2000. Toxicological Effects of 

Methylmercury. Committee on the Toxicological Effects of 

Methylmercury, Board on Environmental Studies and Toxicology, 

National Research Council. 
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112(n)(1) concerning utility HAP emissions, the Utility Study 

and the Mercury Study,5 and completed both by 1998. Prior to 

issuance of the Mercury Study, the EPA engaged in two extensive 

external peer reviews of the document. 

On December 20, 2000, the EPA issued a finding pursuant to 

CAA section 112(n)(1)(A) that it was appropriate and necessary 

to regulate coal- and oil-fired EGUs under CAA section 112 and 

added such units to the list of source categories subject to 

regulation under CAA section 112(d). In making that finding, the 

EPA considered the Utility Study, the Mercury Study, the NAS 

Study, and certain additional information, including information 

about Hg emissions from coal-fired EGUs that the EPA obtained 

pursuant to an information collection request (ICR) under the 

authority of CAA section 114. 65 FR 79826-27.

B. What is the litigation history of this final rule?

Shortly after issuance of the December 2000 finding, an 

industry group challenged that finding in the Court of Appeals 

for the D.C. Circuit (D.C. Circuit). Utility Air Regulatory 

Group (UARG) v. EPA, 2001 WL 936363, No. 01-1074 (D.C. Cir. July 

26, 2001). The D.C. Circuit dismissed the lawsuit holding that 

it did not have jurisdiction because CAA section 112(e)(4) 

provides, in pertinent part, that “no action of the 

 

5 Mercury Study Report to Congress, December 1997; EPA-HQ-OAR2009-0234-3054.
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Administrator...listing a source category or subcategory under 

subsection (c) of this section shall be a final agency action 

subject to judicial review, except that any such action may be 

reviewed under section 7607 of (the CAA) when the Administrator 

issues emission standards for such pollutant or category.” Id. 

(emphasis added).

Pursuant to a settlement agreement, the deadline for 

issuing emission standards was March 15, 2005. However, instead 

of issuing emission standards pursuant to CAA section 112(d), on 

March 29, 2005, the EPA issued the Section 112(n) Revision Rule 

(2005 Action). That action delisted EGUs after finding that it 

was neither appropriate nor necessary to regulate such units 

under CAA section 112. In addition, on May 18, 2005, the EPA

issued the Clean Air Mercury Rule (CAMR). 70 FR 28606. That rule 

established standards of performance for emissions of Hg from 

new and existing coal-fired EGUs pursuant to CAA section 111.

Environmental groups, states, and tribes challenged the 

2005 Action and CAMR. Among other things, the environmental and 

state petitioners argued that the EPA could not remove EGUs from 

the CAA section 112(c) source category list without following 

the requirements of CAA section 112(c)(9).

On February 8, 2008, the D.C. Circuit vacated both the 2005 

Action and CAMR. The D.C. Circuit held that the EPA failed to 
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comply with the requirements of CAA section 112(c)(9) for 

delisting source categories. Specifically, the D.C. Circuit held 

that CAA section 112(c)(9) applies to the removal of “any source 

category” from the CAA section 112(c) list, including EGUs. The 

D.C. Circuit found that, by enacting CAA section 112(c)(9), 

Congress limited the EPA’s discretion to reverse itself and 

remove source categories from the CAA section 112(c) list. The 

D.C. Circuit found that the EPA’s contrary position would 

“nullify §112(c)(9) altogether.” New Jersey v. EPA, 517 F.3d 

574, 583 (D.C. Cir. 2008). The D.C. Circuit did not reach the 

merits of petitioners’ arguments on CAMR, but vacated CAMR for 

existing sources because coal-fired EGUs were already listed 

sources under CAA section 112. The D.C. Circuit reasoned that 

even under the EPA’s own interpretation of the CAA, regulation 

of existing sources’ Hg emissions under CAA section 111 was 

prohibited if those sources were a listed source category under 

CAA section 112.6 Id. The D.C. Circuit vacated and remanded CAMR 

for new sources because it concluded that the assumptions the 

EPA made when issuing CAMR for new sources were no longer 

accurate (i.e., that there would be no CAA section 112 

regulation of EGUs and that the CAA section 111 standards would 

 

6 In CAMR and the 2005 Action, EPA interpreted section 111(d) of 

the Act as prohibiting the Agency from establishing an existing 

source standard of performance under CAA section 111(d) for any 

HAP emitted from a particular source category, if the source 

category is regulated under CAA section 112.
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be accompanied by standards for existing sources). Id. at 583-

84. Thus, CAMR and the 2005 Action became null and void.

On December 18, 2008, several environmental and public 

health organizations filed a complaint in the U.S. District 

Court for the District of Columbia.7 They alleged that the Agency 

had failed to perform a nondiscretionary duty under CAA section 

304(a)(2), by failing to promulgate final CAA 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 CAA section 112(c). The EPA 

settled that litigation. The consent decree resolving the case 

requires the EPA to sign a notice of proposed rulemaking setting 

forth the EPA’s proposed CAA section 112(d) emission standards 

for coal- and oil-fired EGUs by March 16, 2011, and a notice of 

final rulemaking by December 16, 2011.8

 

7 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. (Civ. No. 1:08-cv-02198 

(RMC)).

8 The consent decree originally required EPA to sign a notice of 

final rulemaking no later than November 16, 2011; however, on 

October 21, 2011, pursuant to paragraph 6 of the consent decree, 

the parties agreed to a 30-day extension of the final rule 

deadline. As stated in the stipulation memorializing the 

extension, the parties agreed to the extension of 30 days 

because EPA provided an additional 30 days for public comment 

and the time was necessary to respond to comments submitted on 

the proposed rule. 
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C. What is the relationship between this final rule and other 

combustion rules?

1. CAA section 111

The EPA promulgated revised NSPS for SO2, nitrogen oxides 

(NOX), and PM under CAA section 111 for EGUs (40 CFR Part 60, 

subpart Da) and industrial boilers (IB) (40 CFR Part 60, 

subparts Db and Dc) on February 27, 2006 (71 FR 9866). As noted 

elsewhere, in this action we are finalizing certain amendments 

to 40 CFR Part 60, subpart Da. In developing this final rule, we 

considered the monitoring, testing, and recordkeeping 

requirements of the existing and revised NSPS to avoid 

duplicating requirements to the extent possible.

2. CAA section 112

The EPA has previously developed other non-EGU combustionrelated NESHAP under CAA section 112(d). The EPA promulgated 

final NESHAP for major source industrial, commercial and 

institutional boilers and process heaters (IB) and area source 

industrial, commercial and institutional boilers on March 21, 

2011 (40 CFR Part 63, subpart DDDDD, 76 FR 15608; and subpart 

JJJJJJ, 76 FR 15249, respectively), and promulgated standards 

for stationary combustion turbines (CT) on March 5, 2004 (40 CFR

Part 63 subpart YYYY; 69 FR 10512). In addition to these three 

NESHAP, on March 21, 2011, the EPA also promulgated final CAA 
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section 129 standards for commercial and institutional solid 

waste incineration (CISWI) units, including energy recovery 

units (40 CFR Part 60, subparts CCCC (NSPS) and DDDD (emission 

guidelines); 76 FR 15704); and a definition of non-hazardous 

secondary materials that are solid waste (Non-hazardous Solid 

Waste Definition Rule (40 CFR Part 241, subpart B; 76 FR 

15456)). Electric generating units and IB that combust fossil 

fuel and solid waste, as that term is defined by the 

Administrator pursuant to the Resource Conservation and Recovery 

Act (RCRA), see 76 FR 15456, will be subject to standards issued 

pursuant to CAA section 129 (e.g., CISWI), unless they meet one

of the exemptions in CAA section 129(g)(1). Clean Air Act

section 129 standards are discussed in more detail below.

The two IB (Boiler) NESHAP, the CT NESHAP, and this final 

rule will regulate HAP emissions from sources that combust 

fossil fuels for electrical power, process operations, or 

heating. The differences among these rules are due to the size 

of the units (megawatt (MW), megawatt-electric (MWe), or British 

thermal unit per hour (Btu/hr)), the boiler/furnace technology, 

and/or the portion of their electrical output (if any) for sale 

to any utility power distribution systems.

Pursuant to the CAA, an EGU is “any fossil fuel fired 

combustion unit of more than 25 megawatts that serves a 
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generator that produces electricity for sale. A unit that 

cogenerates steam and electricity and supplies more than onethird of its potential electric output capacity and more than 25 

megawatts electrical output to any utility power distribution 

system for sale shall be considered an electric utility steam 

generating unit.” CAA section 112(a)(8). We consider all of the 

MW ratings quoted in the final rule to be the original rated 

nameplate capacity of the unit. We consider cogeneration to be 

the simultaneous production of power (electricity) and another 

form of useful thermal energy (usually steam or hot water) from 

a single fuel-consuming process.

We consider any combustion unit, regardless of size, that 

produces steam to serve a generator that produces electricity 

exclusively for industrial, commercial, or institutional 

purposes (i.e., makes no sales to the national electrical 

distribution grid) to be an IB unit. We do not consider a fossil 

fuel-fired combustion unit that serves a generator that produces 

electricity for sale to be an EGU under the final rule if the 

size of the combustion unit is less than or equal to 25 MW. 

Units that are 25 MW or less are likely subject to one of the 

two Boiler NESHAP.

Because of the combustion technology of simple-cycle and 

combined-cycle stationary CTs (with the exception of integrated 
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gasification combined cycle (IGCC) units that burn gasified coal 

or petroleum coke synthesis gas/syngas), we do not consider 

these CTs to be EGUs for purposes of this final rule.9

The December 2000 listing discussed above did not list 

natural gas-fired EGUs. Thus, this final rule does not regulate 

a unit that otherwise meets the CAA section 112(a)(8) definition 

of an EGU but that combusts natural gas exclusively or natural 

gas in combination with another fossil fuel where the natural 

gas constitutes 90.0 percent or more of the average annual heat 

input during any 3 consecutive calendar years or 85.0 percent or 

more of the annual heat input in one calendar year. We consider 

such units to be natural gas-fired EGUs notwithstanding the 

combustion of some coal or oil (or derivative thereof) and such 

units are not subject to this final rule.

The CAA does not define the terms “fossil fuel-fired” and 

“fossil fuel.” In this rule, we are finalizing definitions for 

both terms for purposes of this rule. The definition of “fossil 

fuel-fired” will help determine the applicability of the final 

rule to combustion units that sell electricity to the utility 

power distribution system. The definition of “fossil fuel-fired”

establishes the amount of fossil fuel combustion necessary to 

make a unit “fossil fuel-fired” and hence potentially subject to 

 

9 The CT NESHAP regulates HAP emissions from all simple-cycle and 

combined-cycle stationary CTs producing electricity or steam for 

any purpose.
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this final rule. These definitions will help determine 

applicability of the final rule to units that primarily fire 

non-fossil fuels (e.g., biomass) but generally start up using 

either natural gas or distillate oil and may use these fuels (or 

coal) during normal operation for flame stabilization.

In addition, the EPA is finalizing in the definition of 

“fossil fuel-fired” that, among other things, an EGU must fire 

coal or oil for more than 10.0 percent of the average annual 

heat input during any 3 consecutive calendar years or for more 

than 15.0 percent of the annual heat input during any one 

calendar year after the applicable compliance date in order to 

be considered a fossil fuel-fired EGU subject to this final 

rule. The EPA has based these threshold percentage values on the 

definition of “oil-fired” in the Acid Rain Program (ARP) found 

at 40 CFR 72.2. Though the EPA does not have annual heat input 

data for, for example, biomass co-fired EGUs because their use 

is not yet commonplace, we believe this definition accounts for 

the use of fossil fuels for flame stabilization use without 

inappropriately subjecting such units to this final rule.

Units that do not meet the EGU definition will in most 

cases be considered IB units subject to one of the two Boiler 

NESHAP. Thus, for example, a biomass-fired EGU, regardless of 

size, that utilizes fossil fuels for startup and flame 
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stabilization purposes only (i.e., less than or equal to 10.0 

percent of the average annual heat input in any 3 consecutive 

calendar years or less than or equal to 15.0 percent of the 

annual heat input during any one calendar year) is not 

considered to be a fossil fuel-fired EGU under this final rule.

A cogeneration facility that sells electricity to any 

utility power distribution system equal to more than one-third 

of its potential electric output capacity and more than 25 MW

will be considered an EGU if the facility is fossil fuel-fired 

as that term is defined in the final rule.

We recognize that different CAA section 112 rules may 

impact a particular unit at different times. For example, the 

Boiler NESHAP may cover some cogeneration units. Such a unit may 

decide to increase or decrease the proportion of production 

output it supplies 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 MW). 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 final EGU NESHAP.

Another rule intersection may occur where one or more coalor oil-fired EGU(s) share an air pollution control device (APCD) 

and/or an exhaust stack with one or more similarly-fueled IB 
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unit(s). To demonstrate compliance with two different rules, 

either the emissions would need to be apportioned to the 

appropriate source or the more stringent emission limit would 

need to be met. Data needed to apportion emissions are not 

currently required by this final rule or the final boiler NESHAP 

and are not otherwise available. Therefore, the EPA is 

finalizing the requirement to comply with the more stringent 

emission limit.

3. CAA section 129

Clean Air Act section 129 regulates units that combust 

“non-hazardous secondary materials,” as that term is defined by 

the Administrator under the Resource Conservation and Recovery 

Act (RCRA), that are “solid wastes.” On March 21, 2011, the EPA

promulgated the final Non-Hazardous Solid Waste Definition Rule 

(76 FR 15456). Any EGU that combusts any solid waste as defined 

in that final rule is a solid waste incineration unit subject to 

emissions standards under CAA section 129.

In the Non-Hazardous Solid Waste Definition Rule, the EPA

determined that coal refuse from current mining operations is 

not considered to be a “solid waste” if it is not discarded. 

Coal refuse that is in legacy coal refuse piles is considered a 

“solid waste” because it has been discarded. However, if 

discarded coal refuse is processed in the same manner as 
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currently mined coal refuse, the coal refuse would not be 

considered a solid waste but instead would be considered a 

product fossil fuel. Therefore, the combustion of such material 

by a combustion unit would not subject that unit to regulation 

under CAA section 129. Instead, the unit would be subject to 

this final rule if it meets the definition of EGU. In the 

proposed rule, we assumed that all units that combust coal 

refuse and otherwise meet the definition of a coal-fired EGU are 

in fact combusting newly mined coal refuse or coal refuse from 

legacy piles that has been processed such that it is not a solid 

waste. We did not receive any information since proposal that 

would cause us to revise this determination in the final rule.

Further, CAA section 129(g)(1)(B) exempts from regulation

“...qualifying small power production facilities, as 

defined in section 796(17)(C) of Title 16, or 

qualifying cogeneration facilities, as defined in 

section 796(18)(B) of Title 16, which burn homogeneous 

waste...for the production of electric energy or in 

the case of qualifying cogeneration facilities which 

burn homogeneous waste for the production of electric 

energy and steam or forms of useful energy (such as 

heat) which are used for industrial, commercial, 

heating or cooling purposes...”
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If the “homogeneous waste” material that such facilities combust 

is also a fossil fuel, and those facilities otherwise meet the 

definition of an EGU under CAA section 112(a)(8), then those 

facilities are exempt from regulation under CAA section 129 but 

covered under this final rule. For example, a qualifying small 

power production facility or cogeneration facility combusting 

only coal refuse that is a solid waste and a “homogenous waste,”

as that term is defined in the final CAA section 129 CISWI 

standards, would be subject to this final rule if the unit also 

met the definition of EGU.

D. What are the health effects of pollutants emitted from coaland oil-fired EGUs?

This final rule protects air quality and promotes public 

health by reducing emissions of some of the HAP listed in CAA 

section 112(b)(1). Utilities are by far the largest anthropogenic 

source of Hg in the U.S. In addition, EGUs are the largest source 

of HCl, hydrogen fluoride (HF), and selenium (Se) emissions, and 

a major source of metallic HAP emissions including As, chromium 

(Cr), Ni, and others. The discrepancy is even greater now that 

almost all other major source categories have been required to 

control Hg and other HAP under CAA section 112. In 2005, U.S. 

EGUs emitted 50 percent of total domestic anthropogenic Hg

emissions, 62 percent of total As emissions, 39 percent of total 
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cadmium (Cd) emissions, 22 percent of total Cr emissions, 82 

percent of total HCl emissions, 62 percent of total HF 

emissions, 28 percent of total Ni emissions, and 83 percent of 

total Se emissions.10 Exposure to these HAP, depending on 

exposure duration and levels of exposures, is associated with a 

variety of adverse health effects. These adverse health effects 

may include chronic health disorders (e.g., irritation of the 

lung, skin, and mucus membranes; detrimental effects on the 

central nervous system; damage to the kidneys; and alimentary 

effects such as nausea and vomiting). Two of the HAP are 

classified as human carcinogens (As and CrVI) and two as 

probable human carcinogens (Cd and Ni). See 76 FR 25003-25005 

for a fuller discussion of the health effects associated with 

these pollutants.

III. Appropriate and Necessary Finding

A. Overview

In December 2000, the EPA issued a finding pursuant to CAA 

section 112(n)(1)(A) that it was appropriate and necessary to 

regulate coal- and oil-fired EGUs under CAA section 112 and 

added such units to the list of source categories subject to 

regulation under section 112(d). The EPA found that it was 

appropriate to regulate HAP emissions from coal- and oil-fired 

 

10 From 2005 National-Scale Air Toxics Assessment (NATA), 

available at http://www.epa.gov/ttn/atw/nata2005/
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EGUs because, among other reasons, Hg is a hazard to public 

health, and U.S. EGUs are the largest domestic source of Hg 

emissions. The EPA also found it appropriate to regulate HAP 

emissions from EGUs because it had identified certain control 

options that would effectively reduce HAP emissions from U.S. 

EGUs. The EPA found that it was necessary to regulate HAP 

emissions from U.S. EGUs under section 112 because the 

implementation of other requirements under the CAA will not 

adequately address the serious public health and environmental 

hazards arising from HAP emissions from U.S. EGUs and that CAA 

section 112 is intended to address HAP emissions. See 76 FR 

24984-20985 (for further discussion of 2000 finding).

Because several years had passed since the 2000 finding, 

the EPA performed additional technical analyses for the proposed 

rule, even though those analyses were not required. These

analyses included a national-scale Hg risk assessment focused on 

populations with high levels of self-caught fish consumption, 

and a set of 16 case studies of inhalation cancer risks for nonHg HAP. The analyses confirm that it remains appropriate and 

necessary to regulate U.S. EGUs under section 112. 

In the preamble to the proposed rule, the EPA reported the 

results of those additional technical analyses. Those analyses 

confirmed the 2000 finding that it is appropriate to regulate 
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U.S. EGUs under section 112 by demonstrating that 1) Hg 

continues to pose a hazard to public health because up to 28 

percent of watersheds were estimated to have Hg deposition 

attributable to U.S. EGUs that contributes to potential 

exposures above the reference dose for methylmercury (MeHg RfD), 

a level above which there is increased risk of neurological 

effects in children, 2) non-Hg HAP emissions pose a hazard to 

public health because case studies at 16 facilities demonstrated 

that lifetime cancer risks at 4 of the facilities exceed 1 in 1 

million, and 3) U.S. EGUs remain the largest domestic source of 

Hg emissions and several HAP (e.g., HF, Se, HCl), and are among 

the largest contributors for other HAP (e.g., As, Cr, Ni, HCN). 

Thus, in the preamble to the proposed rule, the EPA found that 

Hg and non-Hg HAP emissions from U.S. EGUs pose hazards to 

public health, which confirmed the 2000 finding and demonstrated 

that it remains appropriate to regulate U.S. EGUs under section 

112. 

In the preamble to the proposed rule, the EPA also found 

that it is appropriate to regulate U.S. EGUs because 1) Hg 

emissions pose a hazard to the environment and wildlife, 

adversely impacting species of fish-eating birds and mammals, 2) 

acid gas HAP pose a hazard to the environment because they 

contribute to aquatic acidification, and 3) effective controls 
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are available to reduce Hg and non-Hg HAP emissions from U.S. 

EGUs. 

The additional analyses reported in the preamble to the 

proposed rule also confirmed that it remains necessary to 

regulate U.S. EGU under CAA section 112. These analyses 

demonstrated that 1) Hg emissions from U.S. EGUs remaining in 

2016 are reasonably anticipated to pose a hazard to public 

health after imposition of other CAA requirements, such as the 

Cross-State Air Pollution Rule (CSAPR); 2) U.S. EGUs are 

reasonably anticipated to remain the largest source of Hg in the 

U.S. and thus contribute to the risk associated with exposure to 

MeHg; 3) Hg emissions from U.S. EGUs after imposition of the 

requirements of the CAA were projected to be 29 tons per year in 

2016, similar to levels of Hg emitted today, indicating that 

further substantial reductions in Hg emissions are not 

reasonably anticipated without federal regulations on Hg from 

U.S. EGUs; 4) we cannot be certain that the identified cancer 

risks attributable to non-Hg emissions from U.S. EGUs will be 

addressed through imposition of the requirements of the CAA 

because companies can use compliance strategies for criteria 

pollutants that do not achieve HAP co-benefits (e.g., purchasing 

allowances in a trading program); and 5) we cannot ensure that 

Hg and non-Hg HAP emissions reductions achieved since 2005 would 
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be permanent without federally-binding regulations for Hg from 

U.S. EGUs.

Since issuance of the proposed rule, the EPA has conducted 

peer reviews of the national-scale Hg risk assessment (Hg Risk 

TSD) and the approach for estimating chromium and nickel 

inhalation cancer risk in the case studies.11,12 The peer review 

of the Hg Risk TSD was conducted by EPA’s independent Science 

Advisory Board (SAB). The SAB stated that it “supports the 

overall design of and approach to the risk assessment and finds 

that it should provide an objective, reasonable, and credible 

determination of the potential for a public health hazard from 

mercury emitted from U.S. EGUs.”

13 SAB recommended several 

improvements to the data, methods and documentation of the 

analyses, which EPA has fully addressed in the revised Hg Risk 

TSD. 

As described in the revised Hg Risk TSD, after addressing 

 

11 U.S. EPA. 2011a. National-Scale Assessment of Mercury Risk to 

Populations with High Consumption of Self-caught Freshwater Fish 

In Support of the Appropriate and Necessary Finding for Coaland Oil-Fired Electric Generating Units. Office of Air Quality 

Planning and Standards. November. EPA-452/R-11-009. 

12 U.S. EPA. 2011b. Supplement to Non-mercury Case Study Chronic 

Inhalation Risk Assessment for the Utility MACT Appropriate and 

Necessary Analysis. Office of Air Quality Planning and 

Standards. November.

13 U.S. Environmental Protection Agency-Science Advisory Board 

(U.S. EPA-SAB). 2011. Peer Review of EPA’s Draft National-Scale 

Mercury Risk Assessment. EPA-SAB-11-017. September. Available on 

the internet at 

http://yosemite.epa.gov/sab/sabproduct.nsf/BCA23C5B7917F5BF85257

91A0072CCA1/$File/EPA-SAB-11-017-unsigned.pdf.
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comments from the peer review, the revised results show that up 

to 29 percent of modeled watersheds are estimated to have Hg 

deposition attributable to U.S. EGUs that contributes to 

potential exposures above the MeHg RfD, an increase of one 

percentage point from the results reported in the proposed rule. 

We conclude that Hg emissions from EGUs pose a hazard to public 

health based on the total of 29 percent of modeled watersheds at 

risk. Our analyses show that of the 29 percent of watersheds 

with population at-risk, in 10 percent of those watersheds U.S. 

EGU deposition alone without considering deposition from other 

sources would lead to potential exposures that exceed the MeHg 

RfD, and in 24 percent of those watersheds, total potential 

exposures to MeHg exceed the RfD and U.S. EGUs contribute at 

least 5 percent to Hg deposition.

15,16 Each of these results 

independently supports our conclusion that Hg emissions from 

EGUs pose hazards to public health.

 

15 Because some watersheds with exposures sufficient to exceed 

the RfD with Hg deposition from U.S. EGUs alone without 

considering deposition from other sources also have U.S. EGU 

contributions of more than 5 percent of total Hg deposition,

there is some overlap between the two risk metrics. This 

explains why the total percent of watersheds exceeding either 

risk metric is less than the sum of the individual risk metrics. 

16 Requiring at least a 5 percent EGU contribution is a 

conservative approach given the increasing risks associated with 

incremental exposures above the RfD. Because we are finding 24 

percent of watersheds with populations potentially at risk even 

using this conservative approach, we have confidence that 

emissions of Hg from U.S. EGUs are causing a hazard to public 

health.
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The peer review of the approach to estimate Ni and Cr

cancer risk in the case studies also supported EPA’s assessment. 

The EPA enhanced this analysis in response to the peer review 

and public comments. The results of those revised analyses show

that 6 of 16 modeled facilities have lifetime cancer risks 

greater than 1 in a million, thus confirming that non-Hg HAP 

emissions from U.S. EGUs remain a hazard to public health. Given 

Congress’ determination that categories of sources that emit HAP 

resulting in a lifetime cancer risk greater than 1 in a million 

should not be removed from the CAA section 112(c) source 

category list and should continue to be regulated under CAA 

section 112, the EPA concludes that risk above that level 

represents a hazard to public health.

Based on our consideration of the peer reviews, public 

comments, and our updated analyses, we confirm the findings that 

Hg and non-Hg HAP emissions from U.S. EGUs pose hazards to 

public health and that it remains appropriate to regulate U.S. 

EGUs under CAA section 112. We also conclude that it remains 

appropriate to regulate U.S. EGUs under CAA section 112 because 

of the magnitude of Hg and non-Hg emissions, environmental 

effects of Hg and certain non-Hg emissions, and the availability 

of controls to reduce HAP emissions from EGUs. 
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In addition, we conclude that the hazards to public health 

from Hg and non-Hg emissions from U.S. EGUs are reasonably 

anticipated to remain after imposition of the requirements of 

the CAA. The same is true for hazards to the environment. Thus, 

we confirm that it is necessary to regulate U.S. EGUs under CAA 

section 112.

B. Peer Review of the Hg Risk TSD Supporting the Appropriate and 

Necessary Finding for Coal and Oil-Fired EGUs and EPA Response

In the preamble to the proposed rule, the EPA stated that 

“in making the finding that it remains appropriate and necessary 

to regulate EGUs to address public health and environmental 

hazards associated with emissions of Hg and Non-Hg HAP from 

EGUs, the EPA determined that the Hg Risk TSD supporting EPA’s 

2011 review of U.S. EGU health impacts should be peerreviewed.”

17 We also indicated that due to the court-ordered 

schedule for the final rule, we planned to conduct the peer 

review as expeditiously as possible after issuance of the 

proposed rule, and that the results of the peer review and any 

EPA response would be published before the final rule. Due to 

the extension of the public comment period and the volume of 

public comments received on the analyses supporting the proposed 

rule, we were unable to publish EPA’s response prior to 

signature of the final rule.

 

17 76 FR 25012
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The EPA’s response to the peer review the Hg Risk TSD is 

fully documented in the revised Technical Support Document 

(TSD): National-Scale Assessment of Hg Risk to Populations of 

High Consumption of Self-Caught Fish In Support of the 

Appropriate and Necessary Finding for Coal and Oil-Fired 

Electric Generating Units.

18 The following sections describe the 

peer review process that we followed, provide the peer review 

charge questions presented to the peer review panel, summarize 

the key recommendations from the peer review, and summarize our 

responses to those recommendations.

1. Summary of Peer Review Process

Peer review is consistent with EPA’s open and transparent 

process to ensure that the Agency’s scientific assessments and 

rulemakings are based on the best science available. This 

regulatory action was supported by the Hg Risk TSD, which is a 

highly influential scientific assessment. Therefore, the EPA 

conducted a peer review in accordance with OMB’s Final 

Information Quality Bulletin for Peer Review19 as described 

below. All the materials related to the peer review, including 

the SAB’s final report, can be found in the docket for this 

rulemaking. 

 

18 U.S. EPA, 2011a.

19 Office of Management and Budget (OMB). 2004. Final Information 

Quality Bulletin for Peer Review. December. Available on the 

Internet at http://www.whitehouse.gov/omb/memoranda_fy2005_m05-

03. 
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The EPA commissioned the peer review through EPA’s SAB, 

which provides independent advice and peer review to EPA’s 

Administrator on the scientific and technical aspects of 

environmental issues. The SAB convened a 22-member peer review 

committee. The SAB process for selecting the panel began with 

two Federal Register Notices requesting nominations for the 

Mercury Review Panel.

20 Based on nominations received, a list of 

potential panel members, along with bio-sketches, was posted for 

public comment on the SAB website on April 15, 2011. The members 

of the Mercury Review Panel were announced on May 24, 2011. The 

membership of the panel included representatives of 16 academic 

institutions, 4 state health or environmental agencies, 1 

federal agency, and 1 utility industry organization.21 The panel 

held a public meeting in Research Triangle Park, NC, on June 15-

17, 2011, which included the opportunity for public comment on 

the Hg Risk TSD and the peer review process.22 At the June 15-17 

public meeting, the panel completed a draft peer review report. 

 

20 76 FR 10896 and 76 FR 17649. The first notice requested 

nominations to a Clean Air Scientific Advisory Committee (CASAC) 

panel. Upon review of the scope of the CASAC charter (resulting 

from a public comment received in response to the first notice), 

the SAB determined that it would be more appropriate to form a 

panel under the SAB, rather than CASAC. The second notice 

announced this change and requested nominations for the SAB 

panel.

21 The full list of panel members is documented at 

http://yosemite.epa.gov/sab/sabproduct.nsf/0/9F048172004D93BB852

5783900503486/$File/Determination%20memo%20with%20addendum05.24.11.pdf

22 76 FR 29746
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The minutes of that meeting and the draft peer review report 

were posted to the SAB public website within the public comment 

period for the proposed rule. The panel discussed the draft 

report at a public teleconference on July 12, 2011, during which 

additional opportunities for public comment were provided,23 and 

submitted a revised draft for quality review by the Chartered 

SAB before the end of the public comment period on the rule. The 

Chartered SAB held a public teleconference on September 7, 2011, 

to conduct a quality review of the draft report; this 

teleconference also included a final opportunity for public 

comment.24 The SAB submitted its final report to EPA on September 

29, 2011.25 Notice of all the meetings was published in the 

Federal Register and all of the materials discussed at the SAB 

meetings, including technical documents, presentations, meeting 

minutes, and draft reports were posted for public access on the 

SAB website26 and were added to the docket for the final rule on 

October 14, 2011. 

2. Peer Review Charge Questions

The EPA asked the SAB to comment on the Hg Risk TSD, 

including the overall design and approach and the use of 

 

23 76 FR 39102

24 76 FR 50729

25 U.S. EPA-SAB, 2011. Peer Review of EPA’s Draft National-Scale 

Mercury Risk Assessment. 

26 See

http://yosemite.epa.gov/sab/sabpeople.nsf/WebCommittees/BOARD
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specific models and key assumptions. The EPA also asked the SAB 

to comment on the extent to which specific facets of the 

assessment were well characterized in the Hg Risk TSD. The 

specific charge questions are listed below: 

Question 1. Please comment on the scientific credibility of 

the overall design of the mercury risk assessment as an approach 

to characterize human health exposure and risk associated with 

U.S. EGU mercury emissions (with a focus on those more highly 

exposed). 

Question 2. Are there any additional critical health 

endpoint(s) besides IQ loss, which could be quantitatively 

estimated with a reasonable degree of confidence to supplement 

the mercury risk assessment (see section 1.2 of the Mercury Risk 

TSD for an overview of the risk metrics used in the risk 

assessment)? 

Question 3. Please comment on the benchmark used for 

identifying a potentially significant public health impact in 

the context of interpreting the IQ loss risk metric (i.e., an IQ 

loss of 1 to 2 points or more representing a potential public 

health hazard). Is there any scientifically credible alternate 

decrement in IQ that should be considered as a benchmark to 

guide interpretation of the IQ risk estimates (see section 1.2 

of the Mercury Risk TSD for additional detail on the benchmark 
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used for interpreting the IQ loss estimates)?

Question 4: Please comment on the spatial scale used in 

defining watersheds that formed the basis for risk estimates 

generated for the analysis (i.e., use of 12-digit hydrologic 

unit code classification). To what extent do [Hydrologic Unit 

Code] HUC12 watersheds capture the appropriate level of spatial 

resolution in the relationship between changes in mercury 

deposition and changes in MeHg fish tissue levels? (see section 

1.3 and Appendix A of the Mercury Risk TSD for additional detail 

on specifying the spatial scale of watersheds used in the 

analysis). 

Question 5: Please comment on the extent to which the fish 

tissue data used as the basis for the risk assessment are 

appropriate and sufficient given the goals of the analysis. 

Please comment on the extent to which focusing on data from the 

period after 1999 increases confidence that the fish tissue data 

used are more likely to reflect more contemporaneous patterns of 

Hg deposition and less likely to reflect earlier patterns of Hg 

deposition. Are there any additional sources of fish tissue MeHg 

data that would be appropriate for inclusion in the risk 

assessment? 

Question 6: Given the stated goal of estimating potential 

risks to highly exposed populations, please comment on the use 
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of the 75th percentile fish tissue MeHg value (reflecting 

targeting of larger but not the largest fish for subsistence 

consumption) as the basis for estimating risk at each watershed. 

Are there scientifically credible alternatives to use of the 75th

percentile in representing potential population exposures at the 

watershed level? 

Question 7: Please comment on the extent to which 

characterization of consumption rates and the potential location 

for fishing activity for high-end self-caught fish consuming 

populations modeled in the analysis are supported by the 

available study data cited in the Mercury Risk TSD. In addition, 

please comment on the extent to which consumption rates 

documented in Section 1.3 and in Appendix C of the Mercury Risk 

TSD provide appropriate representation of high-end fish 

consumption by the subsistence population scenarios used in 

modeling exposures and risk. Are there additional data on 

consumption behavior in subsistence populations active at inland 

freshwater water bodies within the continental U.S.? 

Question 8: Please comment on the approach used in the risk 

assessment of assuming that a high-end fish consuming population 

could be active at a watershed if the “source population” for 

that fishing population is associated with that watershed (e.g., 

at least 25 individuals of that population are present in a U.S. 
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Census tract intersecting that watershed). Please identify any 

additional alternative approaches for identifying the potential 

for population exposures in watersheds and the strengths and 

limitations associated with these alternative approaches 

(additional detail on how EPA assessed where specific highconsuming fisher populations might be active is provided in 

section 1.3 and Appendix C of the Mercury Risk TSD). 

Question 9: Please comment on the draft risk assessment’s 

characterization of the limitations and uncertainty associated 

with application of the Mercury Maps approach (including the 

assumption of proportionality between changes in mercury 

deposition over watersheds and associated changes in fish tissue 

MeHg levels) in the risk assessment. Please comment on how the 

output of CMAQ [Community Multiscale Air Quality] modeling has 

been integrated into the analysis to estimate changes in fish 

tissue MeHg levels and in the exposures and risks associated 

with the EGU-related fish tissue MeHg fraction (e.g., matching 

of spatial and temporal resolution between CMAQ modeling and 

HUC12 watersheds). Given the national scale of the analysis, are 

there recommended alternatives to the Mercury Maps approach that 

could have been used to link modeled estimates of mercury 

deposition to monitored MeHg fish tissue levels for all the 

watersheds evaluated? (additional detail on the Mercury Maps 
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approach and its application in the risk assessment is presented 

in section 1.3 and Appendix E of the Mercury Risk TSD). 

Question 10: Please comment on the EPA’s approach of 

excluding watersheds with significant non-air loadings of 

mercury as a method to reduce uncertainty associated with 

application of the Mercury Maps approach. Are there additional 

criteria that should be considered in including or excluding 

watersheds? 

Question 11: Please comment on the specification of the 

concentration-response function used in modeling IQ loss. Please 

comment on whether EPA, as part of uncertainty characterization, 

should consider alternative concentration-response functions in 

addition to the model used in the risk assessment. Please 

comment on the extent to which available data and methods 

support a quantitative treatment of the potential masking effect 

of fish nutrients (e.g., omega-3 fatty acids and selenium) on 

the adverse neurological effects associated with mercury 

exposure, including IQ loss (detail on the concentrationresponse function used in modeling IQ loss can be found in 

section 1.3 of the Mercury Risk TSD). 

Question 12: Please comment on the degree to which key 

sources of uncertainty and variability associated with the risk 

assessment have been identified and the degree to which they are 
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sufficiently characterized. 

Question 13: Please comment on the draft Mercury Risk TSD’s 

discussion of analytical results for each component of the 

analysis. For each of the components below, please comment on 

the extent to which EPA’s observations are supported by the 

analytical results presented and whether there is a sufficient 

characterization of uncertainty, variability, and data 

limitations, taking into account the models and data used: 

mercury deposition from U.S. EGUs , fish tissue MeHg 

concentrations, patterns of Hg deposition with HG fish tissue 

data, percentile risk estimates, and number and frequency of 

watersheds with populations potentially at risk due to U.S. EGU 

mercury emissions. 

Question 14: Please comment on the degree to which the 

final summary of key observations in Section 2.8 is supported by 

the analytical results presented. In addition, please comment on 

the degree to which the level of confidence and precision in the 

overall analysis is sufficient to support use of the risk 

characterization framework described on page 18.

3. Summary of Peer Review Findings and Recommendations

The SAB was generally supportive of EPA’s approach.27 The 

SAB concluded, “[i]n summary, based on its review of the draft 

Technical Support Document and additional information provided 

 

27U.S. EPA-SAB, 2011.
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by EPA representatives during the public meetings, the SAB 

supports the overall design of and approach to the risk 

assessment and finds that it should provide an objective, 

reasonable, and credible determination of the potential for a 

public health hazard from mercury emitted from U.S. EGUs.”

28 The 

SAB further concluded, “[t]he SAB regards the design of the risk 

assessment as suitable for its intended purpose, to inform 

decision-making regarding an ‘appropriate and necessary finding’

for regulation of hazardous air pollutants from coal and oilfired EGUs, provided that our recommendations are fully 

considered in the revision of the assessment.”

29

The SAB report contained many recommendations for improving 

the Hg Risk TSD, which the SAB organized into three general 

themes: (1) improve the clarity of the Hg Risk TSD regarding 

methods and presentation of results, (2) expand the discussion 

of sources of variability and uncertainty, and (3) de-emphasize 

IQ loss as an endpoint. In the following subsection, we provide 

EPA’s response to these recommendations.

4. The EPA’s Responses to Peer Review Recommendations

In response to the peer review, the EPA has substantially 

revised the Hg Risk TSD. The revised Hg Risk TSD addresses all 

of the recommendations from the SAB and includes a detailed list 

 

28 Id.

29 Id.
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of the specific revisions made to the Hg Risk TSD. Revisions in 

response to the main recommendations are summarized below. 

Italicized statements are the SAB’s recommendations, which are 

followed by EPA’s response.

 The watershed-focus of the Hg Risk TSD should be clearly 

stated early in the introduction to the document. We have 

stated clearly in the introduction to the revised Hg Risk 

TSD that the focus of the analysis is on scenarios of high 

fish consumption by subsistence level fishing populations, 

assessed at watersheds where there is the potential for 

such subsistence fishing activity. Specifically, we modeled 

risk for a set of subsistence fisher scenarios at those 

watersheds where (a) we have measured fish tissue Hg data 

and (b) it is reasonable to assume that subsistence-level 

fishing activity could occur. We emphasize the point that 

the analysis is not a representative population-weighted 

assessment of risk. Rather, it is based on evaluating these 

potential exposure scenarios.

 Because IQ does not fully capture the range of 

neurodevelopmental effects associated with Hg exposure, 

analysis of this endpoint should be deemphasized (and moved 

to an appendix) and primary focus should be placed on the 

MeHg RfD-based hazard quotient metric. We modified the 
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structure of the revised Hg Risk TSD accordingly.

 Clarify the rationale for using a Hazard Quotient (HQ) at 

or above 1.5 as the basis for selecting potentially 

impacted watersheds. The SAB fully supported using HQ as 

the risk metric, but we revised the discussion in the Hg 

Risk TSD to clarify why we selected 1.5 as the benchmark. 

We clarified that exposures above the RfD (i.e., an HQ 

above one) represent increasing risk of neurological health 

effects.30 We further clarified that the HQ is calculated to 

only one significant digit, based on the precision in the 

underlying RfD calculations. As a result, rounding 

convention requires that any values at or above 1.5 be 

expressed as an HQ of 2, while any values below 1.5 (e.g., 

1.49) be rounded to an HQ of 1. Thus, MeHg exposures 

leading to an HQ at or above 1.5 for pregnant women are 

considered above the RfD and are associated with increased 

risk of neurological health effects in children born to 

those mothers.

 Regarding the fish tissue dataset used in the Hg Risk TSD, 

clarify which species of Hg is reflected in the underlying 

samples and discuss the implications of differences across 

 

30 As stated in the preamble to the proposal, based on the 

current literature, exposures above the RfD contribute to risk 

of adverse effects.
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states in sampling protocols in introducing bias into the 

analysis. We clarified that in most cases, the fish tissue 

is measured for total Hg. Furthermore, based on the 

scientific literature,31 it is reasonable to assume that 

more than 90 percent of fish tissue Hg is MeHg. Therefore, 

we incorporated an Hg conversion factor32 into our exposure 

calculations to account for the fraction of total Hg that 

is MeHg in fish. We also expanded the discussion of 

uncertainty to address the potential for different sampling 

protocols across states to introduce bias into the Hg Risk 

TSD. 

 Additional detail should be provided on the characteristics 

of the fish tissue Hg dataset, including its derivation and 

the distribution of specific attributes across the dataset 

(e.g., number of fish tissue samples and number of 

different waterbodies in a watershed, number of species 

reflected across watersheds). We included additional 

figures and tables describing the derivation of the 

 

31 See the literature summary in Chapter 4 of U.S. EPA. 2000. 

Guidance for Assessing Chemical Contaminant Data for Use in Fish 

Advisories. Office of Science and Technology, Office of Water, 

Washington, D.C. EPA 823-B-00-007.

32 In the Hg Risk TSD accompanying the proposed rule, we assumed 

that 100 percent of Hg in fish was MeHg. We derived the 0.95 

conversion factor for the revised Hg Risk TSD to reflect that 

most studies show that more than 90 percent of total Hg in fish 

is MeHg. See Chapter 4 of U.S. EPA, 2000.
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watershed-level fish tissue Hg dataset, including the 

filtering steps applied to the original water body level 

data and the additional steps taken to generate the 

watershed-level fish tissue Hg percentile estimates. In 

addition, we included tables summarizing key attributes of 

the dataset (e.g., distribution of fish tissue sample size 

and number of species across the watershed-level 

estimates). 

 Determine whether there is additional (more recent) fish 

tissue data for key states including Pennsylvania, New 

Jersey, Kentucky and Illinois where U.S. EGUs Hg deposition 

may be more significant. We expanded the fish tissue 

dataset by incorporating additional fish tissue data from 

the National Listing of Fish Advisories (NLFA), which 

included additional data for four states (MI, NJ, PA, and 

MN). We also obtained additional data for Wisconsin. These

additional data expanded the number of watersheds in the 

analysis from 2,317 to 3,141, an increase of 36 percent. 

The additional watersheds improve coverage in areas with 

high levels of U.S. EGU-attributable Hg deposition, and 

thus increase our confidence in the overall results of the 

Hg Risk TSD.

 Include additional discussion of the potential that the low 
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sampling rates reflected across many of the watersheds may 

low-bias the 75th percentile fish tissue Hg estimates used 

in estimating potential exposures. In addition, include a 

sensitivity analysis using the 50th percentile estimates to 

provide a bound on the risk. The SAB expressed support for 

the use of the 75th percentile fish tissue Hg value in the 

Hg Risk TSD, while recommending additional discussion of 

the issue. We provided additional description of the fish 

tissue dataset, including distribution of sample sizes and 

fish species across the watersheds, and an improved 

discussion of uncertainty and potential low bias resulting 

from estimation of the 75th percentile fish tissue levels. 

We also included a sensitivity analysis that used the 50th

percentile watershed-level fish tissue Hg level. This 

sensitivity analysis showed that using the 50th percentile 

estimates resulted in a decrease in the number and 

percentage of modeled watersheds with populations 

potentially at-risk from U.S. EGU-attributable MeHg 

exposures, from 29 percent of watersheds exceeding either 

risk metric (i.e., MeHg exposure from U.S. EGUs alone 

exceeds the RfD or total MeHg exposure exceeds the RfD and 

U.S. EGUs contribute at least 5 percent) in the revised Hg 

Risk TSD to 26 percent in the sensitivity analysis in the 
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revised Hg Risk TSD.

 Expand the discussion of caveats associated with the fish 

consumption rates used in the analysis. The SAB was 

generally supportive of the consumption rates used, while 

recommending additional discussion of caveats. We expanded 

the discussion of uncertainty related to the fish 

consumption rates to address the caveats identified by the 

SAB. The uncertainty discussion now explains 1) that highend consumption rates for South Carolina reflect small 

sample sizes, and therefore may be more uncertain, 2) that 

the consumption surveys underlying the studies are older 

(i.e., mostly based on survey data from the 1990s) and 

behavior may have changed (i.e., consumption rates may have 

changed since the surveys were conducted), and 3) that 

consumption rates used in the Hg Risk TSD are annualized 

rather than seasonal rates and thus contribute little to 

overall uncertainty. None of these sources of uncertainty 

is associated with a particular directional bias (e.g., 

neither systematically higher nor lower risk).

 Verify whether the consumption rates are daily values 

expressed as annual averages and whether they are “as 

caught” or “as prepared.” We carefully reviewed the studies 

underlying the fish consumption rates used in the Hg Risk 
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TSD and verified that the rates are annual averages of the 

daily consumption rates and that they represent as prepared 

estimates. We also expanded the explanation of the exposure 

calculations to describe more completely the exposure 

factors and equation used to generate the average daily 

MeHg intake estimates for the subsistence scenarios. 

 Explain the criteria for exclusion of fish less than 7 

inches in length from analysis. We provided the rationale 

for the 7-inch cutoff for edible fish used in the Hg Risk 

TSD. Seven inches represents a minimum size limit for a 

number of key edible freshwater fish species established at 

the state level. For example, Pennsylvania establishes 7 

inches as the minimum size limit for both trout and salmon 

(other edible fish species such as bass, walleye and 

northern pike have higher minimum size limits). The impact 

of the 7-inch cutoff is likely to be quite small, as only 6

percent of potential fish samples were excluded due to this 

criterion.

 Identify the number of watersheds excluded from the 

analysis due to the criterion for excluding watersheds with 

less than 25 members of a source population. The SAB was 

generally supportive of the approach used for identifying 

watersheds with the potential for subsistence activity, 
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while recommending additional information on the results of 

applying the approach. We added a figure to illustrate the 

number of watersheds with fish tissue Hg data used to model 

risk for each of the subsistence fishing scenarios. For all 

scenarios except the female subsistence fishing scenario, 

the exposure scenarios significantly limited the number of 

watersheds. Because the female subsistence fishing scenario 

does not differentiate with regard to ethnicity or socioeconomic status (SES), we applied this scenario to all 

regions of the country and to all watersheds with fish 

tissue Hg data. This reflects our assumption that, given 

the generalized nature of the female subsistence fishing 

scenario, it is reasonable to assume that it could 

potentially occur at any watershed with fish tissue Hg 

data. The female subsistence fishing scenario included in 

the revised risk assessment is similar to the highconsuming female scenario included in the Hg Risk TSD.33

However, the female subsistence fishing scenario is applied 

to all watersheds, while in the scenario for the highconsuming low-income female angler, we only evaluated 

watersheds with a population of at least 25 low-income 

females. The female subsistence fishing scenario provides 

 

33 In the Revised Hg Risk TSD, this population is also referred 

to as the “typical female subsistence consumer.” 
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greater coverage geographically than the high-consuming 

low-income female scenario. As described in the revised Hg 

Risk TSD, the EPA made this change in response to SAB’s 

concerns regarding the potential exclusion of watersheds 

with fewer than 25 individuals and regarding coverage for 

high-end recreational fish consumption.34

 Enhance the discussion of the assumption of a linear 

relationship between changes in Hg deposition and changes 

in fish tissue Hg at the watershed level, including 

providing citations to more recent studies supporting the 

proportional relationship between changes in Hg deposition 

and changes in MeHg fish tissue levels. The SAB supported 

the assumption of a linear relationship between changes in 

Hg deposition and changes in fish tissue Hg at the 

watershed level, while recommending additional supporting 

language. We expanded our discussion of the scientific 

basis for the proportionality assumption and added 

citations for the more recent studies supporting the 

assumption. We also expanded the discussion of 

uncertainties associated with this assumption, including 

 

34 This change led to a very small increase in the number of 

watersheds with populations potentially at-risk. In the Hg Risk 

TSD accompanying the proposed rule, approximately 4 percent of 

modeled watersheds were excluded based on the SES-based 

filtering criteria.
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uncertainties related to the potential for sampled fish 

tissue Hg level to reflect previous Hg deposition, and the 

potential for non-air sources of Hg to contribute to 

sampled fish tissue Hg levels. Each of these sources of 

uncertainty may result in potential bias in the estimate of 

exposure associated with current deposition. If the fish 

tissue Hg levels are too high due to either previous Hg 

deposition or non-air sources of Hg, then the absolute 

level of exposure attributed to both total Hg deposition 

and U.S. EGU-attributable Hg deposition will be biased 

high. However, the percent contribution from U.S. EGUs will 

not be affected as it depends entirely on deposition. The 

EPA took steps to minimize the potential for these biases 

by 1) only using fish tissue Hg samples from after 1999, 

and 2) screening out watersheds that either contained 

active gold mines or had other substantial non-U.S. EGU 

anthropogenic emissions of Hg. The SAB concluded that the 

EPA’s approach to minimizing the potential for these biases 

to affect the results of the Hg Risk TSD is sound. In 

addition, we conducted several sensitivity analyses to 

gauge the impact of excluding watersheds with the potential 

for non-EGU Hg loading. We found that the estimates of the 

percent of modeled watersheds with populations potentially 
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at-risk were largely insensitive to these exclusions, 

suggesting that any potential biases from including 

watersheds with potential non-air Hg loadings are likely to 

be small.

 Additional sources of variability should be discussed in 

terms of the degree to which they are reflected in the 

design of the risk assessment and the impact that they 

might have on risk estimates. These include: 1) the 

geographic patterns of populations of subsistence fishers, 

including how this factor interacts with the limited 

coverage we have for watersheds with our fish tissue Hg 

data, 2)the protocols used by states in collecting fish 

tissue Hg data, 3) body weights for subsistence fishing 

populations and the impact that this might have on exposure 

estimates, and 4) preparation and cooking methods which 

affect the conversion of fish tissue Hg levels (as 

measured) into “as consumed” values. We expanded the 

discussion of sources of variability in the revised Hg Risk 

TSD to more fully address these sources of variability. The 

Hg Risk TSD quantitatively reflected many aspects of 

variability, including spatial and temporal variability in 

Hg emissions, Hg deposition, fish tissue Hg levels, and 

subsistence behavior. After evaluating the aspects of 
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variability assessed qualitatively in the Hg Risk TSD such 

as temporal response in fish tissue, we do not believe that 

quantitatively incorporating any of these aspects would 

substantially change the risk results given the stated goal 

of the analysis to identify watersheds where potential 

exposures to MeHg from self-caught fish consumption could 

exceed the RfD.

 Additional sources of uncertainty should be discussed in 

terms of their potential impact on risk estimates. These 

include: 1) emissions inventory used in projecting total 

and U.S. EGU-attributable Hg deposition, including the 

projection of reductions in U.S. EGU emissions for the 2016 

scenario, 2) air quality modeling with CMAQ including the 

prediction of future air quality scenarios, 3) ability of 

the Mercury Maps-based approach for relating Hg deposition 

to MeHg in fish to capture Hg hotspots, 4) the limited 

coverage that we have with fish tissue Hg data for 

watersheds in the U.S. and implications for the Hg Risk 

TSD, 5) the preparation factor used to estimate “as 

consumed” fish tissue Hg levels, 6) the proportionality 

assumption used to relate changes in Hg deposition to 

changes in fish tissue Hg levels at the watershed-level, 

7)characterization of the spatial location of subsistence 
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fisher populations (including the degree to which these 

provide coverage for high-consuming recreational fishers), 

and 8) application of the RfD to low SES populations and 

concerns that this could low-bias the risk estimates. We 

expanded the discussion of sources of uncertainty presented 

in the revised TSD to address more fully these sources of 

uncertainty and the potential impact on risk estimates. 

Regarding these eight additional sources of uncertainty, we 

have 1) evaluated the uncertainties in the emissions and 

determined that while an important source of uncertainty, 

we are not able to quantify emissions uncertainty in the 

risk analysis, but have determined that the emissions 

inventories and emissions models represent the best 

available methods for predicting Hg emissions in the U.S., 

2) evaluated the uncertainties in the Hg deposition 

predictions and determined that while an important source 

of uncertainty, we are not able to quantify uncertainty in 

Hg deposition in the Hg Risk TSD. Moreover, the CMAQ model 

used to estimate deposition is based on peer reviewed 

science and represents the best available method for 

predicting Hg deposition in the U.S., 3) evaluated the 

ability of the Mercury Maps-based approach for relating Hg 

deposition to MeHg in fish to capture Hg hotspots and 
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determined that while finer resolution deposition modeling 

might reveal additional areas with elevated deposition, the 

12 kilometer (km) deposition modeling matches well with the 

watershed size selected for the analysis, and thus the use 

of 12 km deposition estimates with the Mercury Maps based 

approach will not be a large source of uncertainty, 

4)evaluated the limited coverage that we have with fish 

tissue Hg data for watersheds in the U.S. and implications 

for the Hg Risk TSD and based on the SAB’s recommendations, 

we supplemented the coverage of watersheds by obtaining 

additional fish tissue Hg samples for areas heavily 

impacted by U.S. EGU deposition, thus reducing the 

uncertainty in the analysis, 5) evaluated the uncertainty 

in the preparation factor and determined that the level of 

uncertainty is low, and as such would have minimal impact 

on the risk estimates, 6) evaluated the uncertainty 

resulting from the proportionality assumption used to 

relate changes in Hg deposition to changes in fish tissue 

Hg levels at the watershed-level, and determined, based 

both on quantitative sensitivity analyses and qualitative 

assessments, that this source of uncertainty is not likely 

to greatly influence the results, and is not likely to have 

a specific directional bias, 7) evaluated the uncertainty 
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related to characterization of the spatial locations of 

subsistence populations and determined that uncertainty 

could be reduced by focusing the risk estimates on female 

subsistence fishing populations, which are assumed to have 

the potential to fish in all watersheds, in response to 

SAB’s concerns regarding potential exclusion of watersheds 

with fewer than 25 individuals and 8) evaluated the 

potential impact of the uncertainty in application of the 

RfD to low SES populations. The EPA determined that due to 

the method used in calculating the RfD, we have confidence 

that the RfD provides protection for low SES populations. 

 Expand the sensitivity analyses (over those included in the 

original risk assessment) to address uncertainty related to 

the use of the 75th percentile fish tissue Hg value (at 

each watershed) as the core risk estimate. Based on the 

SAB’s recommendation, we added a sensitivity analysis using 

the median fish tissue Hg estimate (at the watershed 

level). This sensitivity analysis showed that use of the 

median fish tissue Hg concentration instead of the 75th

percentile resulted in a relatively small decrease (i.e., 

10 percent) in the estimates of watersheds with populations 

potentially at-risk, and did not substantially change the 

conclusions of the risk assessment.
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C. Summary of Results of Revised Hg Risk TSD of Risks to 

Populations with High Levels of Self-Caught Fish Consumption

Based on the recommendations we received from the SAB, we 

revised the quantitative analysis of risk to subsistence fishing 

populations with high levels of fish consumption. Our revision 

to the quantitative risk results reflects three key 

recommendations from the SAB, including 1) addition of 824 

watersheds based on additional fish tissue Hg sample data we 

obtained from states and the National Listing of Fish 

Advisories, 2) application of a 0.95 adjustment factor to the 

reported fish tissue Hg concentrations to account for the 

fraction that is MeHg, and 3) inclusion of all watersheds with 

fish samples that meet the filtering criteria35 in representing 

potential exposures associated with increased risk of neurologic 

health effects for female subsistence fishing populations. 

Based on these revisions, our estimates of the number and 

percent of modeled watersheds with populations potentially atrisk from exposure to EGU-attributable MeHg changed from those 

presented in the preamble to the proposed rule.36 For the 99th

 

35 The watersheds were filtered to exclude watersheds that: (a) 

were not freshwater, (b) did not have fish sampling data since 

2000, (c) did not have fish larger than 7 inches in length, (d) 

contained active gold mines or (e) had substantial non-air Hg 

loading.

36 Since the time of the analyses conducted in support of the 

proposed rule, the EPA updated IPM modeling to reflect the most 

recently available information, including public comments and 
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percentile consumption scenario, the number of watersheds with 

fish tissue Hg samples where subsistence fishing populations may 

be at-risk from exposure to EGU-attributable MeHg increased from 

672 to 917 (an increase of 36 percent). For this same scenario, 

the total percent of modeled watersheds with populations 

potentially at-risk from either risk metric (i.e., MeHg exposure 

from U.S. EGUs alone exceeds the RfD or total MeHg exposure 

exceeds the RfD and U.S. EGUs contribute at least 5 percent)

increased from 28 percent estimated at proposal to 29 percent 

after addressing SAB recommendations. The increase in the total 

percent of modeled watersheds with populations potentially atrisk using the expanded geographic coverage of watersheds 

provides additional confidence that emissions of Hg from U.S. 

EGUs pose a hazard to public health. For the 99

th percentile 

consumption scenario, the percent of modeled watersheds with 

populations potentially at-risk from total potential exposures 

to MeHg that exceed the RfD and U.S. EGUs contribute at least 5 

percent increased from 22 percent to 24 percent. For the 99

th

 

the final CSAPR (see IPM Documentation for further details on 

these updates, which is available in the docket). Compared to 

the modeling conducted at proposal, these updates are projected 

to result in greater reductions in criteria pollutants, and also 

to have a slightly greater impact on U.S. EGU Hg emissions. 

Based on the revised projection for 2016, the EPA estimates that 

U.S. EGUs would emit 27 tons of Hg, as compared to the 29 tons 

we modeled for the Hg Risk TSD. We do not expect this 2 ton 

difference to substantially change the mercury risks reported in 

the preamble to the proposed rule, as this represents less than 

a 10 percent reduction in Hg emissions. 
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percentile consumption scenario, the percent of modeled 

watersheds with populations potentially at-risk based on Hg 

deposition from U.S. EGUs alone decreased from 12 percent to 10

percent.

The additional sensitivity analyses conducted in response 

to the SAB peer review showed that the estimates of the percent 

of modeled watersheds with populations potentially at-risk are 

robust to alternative assumptions about both the watersheds 

included in the analysis and the selection of the 50th percentile 

or 75th percentile fish tissue Hg level. Sensitivity analyses 

excluding entire states with the potential for historical 

loadings of Hg from non-air sources37 resulted in an increase 

from 29 percent to 33 percent in the total percent of modeled 

watersheds with populations potentially at-risk exceeding either 

risk metric (i.e., U.S. EGUs alone or total potential exposures 

to MeHg exceed the RfD and U.S. EGUs contribute at least 5 

percent). Including only watersheds in the top 25th percentile of 

U.S. EGU deposition resulted in an increase in the total percent 

of modeled watersheds with populations potentially at-risk 

exceeding either risk metric, from 29 percent to 30 percent. 

Using the 50th percentile fish tissue Hg level resulted in a 

 

37 The SAB noted that areas with substantially elevated fish 

tissue Hg levels could also be characterized by lakes and rivers 

with high natural methylation rates, and thus some of the states 

we excluded for this sensitivity analysis might not have fish 

tissue Hg levels that reflect non-U.S. EGU Hg loadings.
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decrease in the total percent of modeled watersheds with 

populations potentially at-risk exceeding either risk metric, 

from 29 percent to 26 percent. On balance, these sensitivity 

analyses do not substantially reduce the percent of modeled 

watersheds with populations potentially at-risk, and thus 

confirm the finding that Hg emissions from U.S. EGUs pose a 

hazard to public health. In fact, given the broader coverage of 

modeled watersheds in the revised analysis, we have even greater 

confidence in our finding that Hg emissions from U.S. EGUs pose 

a hazard to public health. 

D. Peer Review of the Approach for Estimating Cancer Risks 

Associated with Cr and Ni Emissions in the U.S. EGU Case Studies 

of Cancer and Non-Cancer Inhalation Risks for Non-Hg HAP and EPA 

Response

As explained in the preamble to the proposed rule, the EPA 

submitted for peer review its characterization of the chemical 

speciation for the emissions of Cr and Ni used in the non-Hg HAP 

inhalation risk case studies. The remaining aspects of the nonHg HAP case study risk assessments used methods that were 

previously peer reviewed. Specifically, the methodologies used 

to conduct the non-Hg case studies are consistent with those 

used to conduct inhalation risk assessments under EPA’s Risk and 

Technology Review (RTR) program. Because the RTR assessments are 
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considered to be highly influential science assessments, the 

methodologies used to conduct them were subject to a peer review 

by the SAB in 2009. The SAB issued its peer review report in May 

2010.38 The report endorsed the risk assessment methodologies 

used in the program, and made a number of technical 

recommendations for EPA to consider as the RTR program evolves.

The EPA’s case studies identified Cr and Ni emissions as 

the key drivers of the estimated inhalation cancer risks for 

EGUs. Because these results hinged on specific scientific 

interpretations of data used to characterize EGU emissions of Cr 

and Ni, the EPA conducted a letter peer review of its analysis 

and interpretation of those data relative to the quantification 

of inhalation risks associated with Cr and Ni emissions from 

U.S. EGUs. The following sections describe the peer review 

process, enumerate the peer review charge questions presented to 

the peer review panel, summarize the key recommendations from 

the peer review, and summarize our responses to those 

recommendations.

1. Summary of Peer Review Process

 

38 U.S. Environmental Protection Agency – Science Advisory Board 

(U.S. EPA-SAB). 2010. Review of EPA’s draft entitled, “Risk and 

Technology Review (RTR) Risk Assessment Methodologies: For 

Review by the EPA’s Science Advisory Board with Case Studies –

MACT I Petroleum Refining Sources and Portland Cement 

Manufacturing”. EPA-SAB-10-007. May. Available on-line at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/4AB3966E263D943A85257

71F00668381/$File/EPA-SAB-10-007-unsigned.pdf
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The EPA asked three independent, external peer reviewers 

representing government, academic and the private sector to 

review of the methods for developing inhalation cancer risk 

estimates associated with emissions of Cr and Ni compounds from 

coal- and oil-fired EGUs in support of the appropriate and 

necessary finding. The approaches and rationale for the 

technical and scientific considerations used to derive 

inhalation cancer risks were summarized in the draft document 

entitled, “Methods to Develop Inhalation Cancer Risk Estimates 

for Chromium and Nickel Compounds.” The peer reviewers received 

several charge questions (three questions on Cr and two 

questions on Ni, which are provided below) on the technical and 

scientific relevance of the approaches used to develop the 

inhalation unit risk estimates. The EPA also provided 

information on Cr speciation profiles for different industrial 

sources, as well as information on the Ni speciation of PM from 

oil-fired EGUs.

2. Peer Review Charge Questions

Below, we present the charge questions posed to the peer 

reviewers to help guide their review and development of 

recommendations to EPA on key issues relevant to the 

characterization of risks from EGU emissions containing either 

Cr or Ni compounds. 
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The EPA asked three questions regarding Cr and Cr 

compounds:

Question 1: Do EPA’s judgments related to speciated Cr 

emissions adequately take into account the available Cr 

speciation data? 

Question 2: Has EPA selected the species of Cr (i.e., 

hexavalent Cr, Cr(VI)) that accurately represents the toxicity 

of Cr and Cr compounds?

Question 3: Are the assumptions used in past analysis 

scientifically defensible, and are there alternatives that EPA 

should consider for future analysis? 

The EPA asked two questions regarding Ni and Ni compounds:

Question 1: Do EPA’s judgments related to speciated Ni 

emissions adequately take into account available speciation 

data, including recent industry spectrometry studies?

Question 2: Based on the speciation information available 

and on what we know about the health effects of Ni and Ni 

compounds, and taking into account the existing Unit Risk 

Estimates (URE) values (i.e., values derived for EPA’s 

Integrated Risk Information System (IRIS), California 

Environmental Protection Agency (Cal EPA) and Texas Commission 

on Environmental Quality (TCEQ)), the EPA has provided several 
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approaches39 to derive unit risk estimates that may be more 

scientifically defensible than those used in past analyses. 

Which of the options presented would result in more accurate and 

defensible characterization of risks from exposure to Ni and Ni 

compounds? Are there alternative approaches that EPA should 

consider?

3. Summary of Peer Review Findings and Recommendations

Regarding Cr and Cr compounds, all three reviewers 

considered Cr(VI) as the species likely to be driving cancer 

risks based on solid evidence from the health effects database 

for Cr and Cr compounds. All three authors also considered EPA’s 

use of the average of the range of the available speciation data 

(i.e., 12 percent and 18 percent Cr(VI) contained in coal- and 

oil-fired EGUs, respectively) as a reasonable approach for the 

derivation of default speciation profiles to be used when there 

is no speciation data available. All reviewers agreed that there 

is high uncertainty associated with the variability in the 

speciation data available for Cr (e.g., range of approximately 4 

to 23 percent Cr(VI) from coal-fired units). One of the 

reviewers recommended several additional studies for EPA’s 

 

39 See section 3.3 of U.S. Environmental Protection Agency (U.S. 

EPA). 2011c. Methods to Develop Inhalation Cancer Risk Estimates 

for Chromium and Nickel Compounds. Office of Air Quality 

Planning and Standards. October. 
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consideration; the EPA considered these in finalizing the 

report. 

Regarding Ni and Ni compounds, the reviewers agreed with 

the views of the international scientific bodies, which consider 

Ni compounds carcinogenic as a group. One reviewer recommended 

that the EPA review several additional Ni speciation data that 

suggests that sulfidic Ni compounds (which the reviewer 

considered as the most potent carcinogens within the group of 

all Ni compounds) are present at low levels in emissions from 

EGUs. In addition, this reviewer pointed out that there is a 

recently proposed model that may explain the differences in 

carcinogenic potential across Ni compounds.

4. The EPA’s Responses to Peer Review Recommendations

We summarize EPA’s basic responses to the peer review 

comments below, first for Cr-related issues, and second for Nirelated issues, which are reflected in the revised document. 40

a. Cr and Cr compounds:

In agreement with the peer reviewers and based on the 

health effects information available for Cr, the EPA assigns 

high confidence in the assumption that Cr(VI) is the 

carcinogenic species driving the risk of Cr-emitting facilities. 

In agreement with the reviews, the EPA considers derivation of 

default speciation profiles based on the mass of Cr(VI) a 

 

40 U.S. EPA, 2011c.
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reasonable approach. As suggested by one of the reviewers, the 

EPA reviewed two potentially relevant studies, one of which 

showed coal combustion emissions containing as much as 43 

percent Cr(VI),41 which suggests that the EPA’s quantitative 

approach could actually underestimate Cr(VI) inhalation risks. 

However, the other study reviewed by EPA on speciation of Cr in 

coal combustion showed Cr(VI) percentage levels close to 

detection limits (i.e., 3 to 5 percent of total Cr, which was 

close to the limit of detection in this study).42 Thus, the more 

recent speciation data available is unlikely to reduce the 

uncertainty of the Cr speciation analyses used by EPA as the 

bases for risk characterization analysis.

In agreement with the peer reviewers, the EPA also 

recognizes that the confidence in the default speciation 

profiles is low because the profiles are based on a limited data 

set with a wide range of percentages of Cr(VI) across the 

different samples. 

b. Ni and Ni compounds:

Based on the views of the major scientific bodies mentioned 

above and the peer reviewers that commented on EPA’s approaches 

 

41 Galbreath KC, Zygarlicke CJ. 2004. “Formation and chemical 

speciation of arsenic-, chromium-, and nickel-bearing coal 

combustion PM2.5,” Fuel Process Technol 85:701-726.

42 Huggins FE, Najih M, Huffman GP. 1999. “Direct speciation of 

chromium in coal combustion by-products by X-ray absorption fine 

structure spectroscopy,” Fuel Process Technol 78:233-242.
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to risk characterization of Ni compounds, the EPA considers all 

Ni compounds to be carcinogenic as a group and the EPA does not 

consider Ni speciation or Ni solubility to be strong 

determinants of Ni carcinogenicity. These scientific bodies also 

recognize that based on the data available, the precise Ni 

compound(s) responsible for the carcinogenic effects in humans 

is not always clear, and that there may be differences in the 

potential toxicity and carcinogenic potential across Ni 

compounds. Nevertheless, studies in humans indicate that various 

mixtures of Ni compounds (including Ni sulfate, sulfides and 

oxides, alone or in combination) encountered in the Ni refining 

industries may cause cancer in humans, and there is no reason to 

expect anything different from this for mixtures of Ni compounds 

from other emission sources. One of the reviewers suggested we 

consider views by some authors that believe that water soluble 

Ni, such as Ni sulfate, should not be considered a human 

carcinogen. This view is based primarily on a negative Ni 

sulfate 2-year rodent bioassay by the National Toxicology 

Program (NTP) (which is different from the positive 2-year NTP 

bioassay for Ni subsulfide).43,44,45 One review article identifies 

 

43 Oller A. 2002. “Respiratory carcinogenicity assessment of 

soluble nickel compounds.” Environ Health Perspect. 110:841-844.

44 Heller JG, Thornhill PG, Conard BR. 2009. “New views on the 

hypothesis of respiratory cancer risk from soluble nickel 

exposure; and reconsideration of this risk’s historical sources 

in nickel refineries.” J Occup Med Toxicol. 4:23.
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the discrepancies between the animal and human data (i.e., from 

studies of cancers in workers inhaling certain forms of Ni 

versus inhalation studies suggesting different carcinogenic 

potential in rodents with different Ni compounds) and states 

that the epidemiological data available clearly support an 

association between Ni and increased cancer risk, although the 

article acknowledges that the data are weakest regarding water 

soluble Ni. In addition, the EPA identified a recent review46

that highlights the robustness and consistency of the 

epidemiological evidence across several decades showing 

associations between exposure to Ni and Ni compounds (including 

Ni sulfate) and cancer. 

Regarding the second charge question on Ni compounds, two 

reviewers suggested using the URE derived by the TCEQ47 for all 

Ni compounds as a group, rather than the one derived by the 

Integrated Risk Information System (IRIS, 1991)48 specifically 

 

45 Goodman JE, Prueitt RL, Thakali S, and Oller AR. 2011. “The 

nickel iron bioavailability model of the carcinogenic potential 

of nickel-containing substances in the lung.” Crit Rev Toxicol

41:142-174.

46 Grimsrud TK and Andersen A. “Evidence of carcinogenicity in 

humans of water-soluble nickel salts.” J Occup Med Toxicol.

2010. 5:1-7. Available online at http://www.ossupmed.com/content/5/1/7.

47 Texas Commission on Environmental Quality (TCEQ). 2011. 

Development Support Document for nickel and inorganic nickel 

compounds. Available online at 

http://www.tceq.state.tx.us/assets/public/implementation/tox/dsd

/final/june11/nickel_&_compounds.pdf

48 U.S. EPA, 1991. Integrated Risk Information Service (IRIS) 
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for Ni subsulfide. The third reviewer did not comment on an 

alternative approach. Considering this, to develop our primary 

risk estimate, the EPA decided to use a health protective 

approach by applying 100 percent of the current IRIS URE for Ni 

subsulfide, rather than assuming that 65 percent of the total 

mass of emitted Ni might be Ni subsulfide, as used in previous 

analyses. We used the IRIS URE value because IRIS values are 

preferred given the conceptual consistency with EPA risk 

assessment guidelines and the level of peer review that such 

values receive. We used 100 percent of the IRIS value because of 

the concerns about the potential carcinogenicity of all forms of 

Ni raised by the major national and international scientific 

bodies, and recommendations of the peer reviewers. Nevertheless, 

taking into account that there are potential differences in 

toxicity and/or carcinogenic potential across the different Ni 

compounds, and given that two URE values have been derived for 

exposure to mixtures of Ni compounds that are two to three fold 

lower than the IRIS URE for Ni subsulfide, the EPA also 

considers it reasonable to use a value that is 50 percent of the 

IRIS URE for Ni subsulfide for providing an estimate of the 

lower end of a plausible range of cancer potency values for 

different mixtures of Ni compounds.

 

assessment for nickel subsulfide. Available at: 

http://www.epa.gov/iris/subst/0273.htm.
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Although this report focused primarily on cancer risks 

associated with emissions containing Ni compounds, it is 

important to note that comparative quantitative analyses of noncancer toxicity of Ni compounds indicate that Ni sulfate is as 

toxic or more toxic than Ni subsulfide or Ni oxide which does 

not support the notion that the solubility of Ni compounds is a 

strong determinant of its toxicity.49,50

E. Summary of Results of Revised U.S. EGU Case Studies of Cancer 

and Non-Cancer Inhalation Risks for Non-Hg HAP 

Based on the results of the peer review and public comments 

on the non-Hg case study chronic inhalation risk assessment, we 

made several changes to the emissions estimates, dispersion 

modeling, and risk characterization for the modeled case study 

facilities. Key changes include 1) changes in emissions, 2) 

changes in stack parameters for some facilities based on new 

data received during the public comment period, 3) use of 

updated versions of AERMOD and its input processors (AERMAP, 

AERMINUTE, and AERMET), and 4) use of 100 percent of the current 

IRIS URE for Ni subsulfide to calculate Ni-associated inhalation 

 

49 Haber LT, Allen BC, Kimmel CA. 1998. “Non-Cancer Risk 

Assessment for Nickel Compounds: Issues Associated with DoseResponse Modeling of Inhalation and Oral Exposures.” Toxicol 

Sci. 43:213-229.

50 National Toxicology Program (NTP). 1996. Technical Report 

Series No. 454, Toxicology and carcinogenesis studies of nickel 

sulfate hexahydrate. July. Available online at 

http://ntp.niehs.nih.gov/ntp/htdocs/LT_rpts/tr454.pdf.
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cancer risks (rather than assuming that the Ni might be 65 

percent as potent as Ni subsulfide). 

Based on estimated actual emissions, the highest estimated 

individual lifetime cancer risk from any of the 16 case study 

facilities was 20 in a million, driven by Ni emissions from the 

one case study facility with oil-fired EGUs. Of the facilities 

with coal-fired EGUs, five facilities had maximum individual 

cancer risks greater than one in a million51 (the highest was 

five in a million), with the risk from four due to emissions of 

Cr(VI) and the risk from one due to emissions of Ni.52 There were 

also two facilities with coal-fired EGUs that had maximum 

individual cancer risks equal to one in a million. All of the 

facilities had non-cancer Target Organ Specific Hazard Index 

(TOSHI)53 values less than one, with a maximum TOSHI value of 0.4 

 

51 A risk level of 1 in a million implies a likelihood that up to 

one person, out of one million equally exposed people would 

contract cancer if exposed continuously (24 hours per day) to 

the specific concentration over 70 years (an assumed lifetime). 

This would be in addition to those cancer cases that would 

normally occur in an unexposed population of one million people.

52 When the lower end of the cancer potency range for Ni was used 

to develop risk estimates, 5 of the 16 facilities had maximum 

cancer risks exceeding 1 in a million, and the maximum 

individual cancer risk for any single facility fell to 10 in a 

million. 

53 The target-organ-specific hazard index (TOSHI) is a metric 

used to assess whether there is an appreciable risk of 

deleterious (noncancer) effects to a specific target organ due 

to continuous inhalation exposures over a lifetime. If a TOSHI 

value is less than or equal to one, such effects are unlikely. 

For TOSHI values greater than one, there is an increased risk of 

such effects.
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(also driven by Ni emissions from the one case study facility 

with oil-fired EGUs).

Since these case studies do not cover all facilities in the 

category, and since our assessment does not include the 

potential for impacts from different EGU facilities to overlap 

one another (i.e., these case studies only look at facilities in 

isolation), the maximum risk estimates from the case studies 

likely underestimates true maximum risks for the source 

category.

Based on the fact that six U.S. EGUs were estimated to meet 

or exceed the CAA section 112(c)(9) criterion of one in a 

million, EGUs cannot be removed from the list of source 

categories to be regulated under CAA section 112.

F. Public Comments and Responses to the Appropriate and 

Necessary Finding

1. Legal Aspects of Appropriate and Necessary Finding

a. History of Section 112(n)(1)(A). 

Comment: One commenter provided a detailed history of EPA’s 

regulatory actions concerning EGUs and implementation of CAA 

section 112(n)(1)(A). The same commenter implies that the EPA’s 

2000 appropriate and necessary finding and listing of EGUs was 

flawed because the Agency did not comply with CAA section 307(d) 

rulemaking process. The commenter sought review of the 2000 
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notice in the U.S. Court of Appeals for the District of Columbia 

Circuit, which was dismissed by the D.C. Circuit. Utility Air 

Regulatory Group v. EPA, No. 01-1074 (D.C. Cir. July 26, 2001).

The commenter then characterizes at length the 2005 EPA action 

that revised the interpretation of CAA section 112(n)(1)(A) and, 

which the D.C. Circuit concluded illegally removed EGUs from the 

CAA section 112(c) list of sources that must be regulated under 

CAA section 112. See New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 

2008). The commenter notes that the D.C. Circuit did not rule on 

the legal correctness or the sufficiency of the factual record 

supporting EPA’s 2000 listing decision or on the factual 

correctness of EPA’s later decision to reverse its CAA section 

112(n)(1)(A) determination. The commenter noted further that the 

D.C. Circuit indicated that the listing decision could be 

challenged when the Agency issued the final CAA section 112(d) 

standards pursuant to CAA section 112(e)(4). The commenter 

concluded by asserting that the Agency could not ignore the 

history associated with the regulation of EGUs under section 112 

and that two earlier dockets - Docket ID. No. A-92-55 and Docket 

ID. No. EPA-HQ-OAR-2002-0056 – are also part of this long 

rulemaking effort and must be accounted for in conjunction with 

Docket No. EPA-HQ-OAR-2009-0234 if all pertinent material and 

comments are to be part of the rulemaking record.
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Response: The commenter characterizes the regulatory history of 

the rule EPA proposed on May 3, 2011. To the extent that 

characterization is inconsistent with the lengthy regulatory 

history EPA provided in the preamble to the May 3, 2011 rule, we 

disagree. We address several of the statements in more detail 

below.

First, the commenter makes much of the fact that the EPA 

did not go through CAA section 307(d) notice and comment 

rulemaking when making the appropriate and necessary finding and 

listing decision in 2000. However, the commenter’s complaint is 

without foundation. The CAA does not require CAA section 307(d) 

rulemaking for listing decisions. In fact, CAA section 112(e)(4) 

specifically provides that listing decisions may only be 

challenged “when the Administrator issues emission standards for 

such...[listed] category.” Second, the commenter challenged the 

listing decision in the U.S. Court of Appeals for the District 

of Columbia Circuit (Court) and, on July 26, 2001, the Court 

granted EPA’s motion to dismiss that action based on the plain 

language of CAA section 112(e)(4). Moreover, in addition to the 

2000 notice, the EPA clearly articulated its basis for listing 

EGUs in this proposed rule, which is consistent with CAA section 

307(d), and the commenter was provided an ample opportunity to 

comment. Finally, the commenter asserts that the rulemaking 
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docket for this action is incomplete because the Agency did not 

include two earlier dockets - Docket ID. No. A-92-55 and Docket 

ID. No. EPA-HQ-OAR-2002-0056 - for the Section 112(n) Revision 

Rule, 70 F.R. 15994 (March 29, 2005), and the reconsideration of 

the Section 112(n) Revision Rule, 71 F.R. 33388 (June 9, 2006), 

respectively. The commenter is incorrect because EPA 

incorporated by reference the two dockets at issue. See EPA-HQOAR-2009-0234-3056. 

Comment: One commenter stated that the EPA has assessed the 

public health risks posed by HAP emissions from coal- and oilfired EGUs for the last 40 years. According to the commenter, 

throughout that time, the EPA has come to a single repeated 

conclusion that HAP emissions from EGUs pose little or no risk 

to public health. Based on this conclusion, the EPA has properly 

chosen not to require EGUs to install expensive, new pollution 

control equipment to control HAP emissions. The commenter 

asserts that, in this proposed rule, the EPA shifts its opinion 

on the health impacts of EGU HAP emissions 180 degrees and now 

seeks to impose sweeping regulatory requirements on all power 

plants. According to the commenter, the EPA’s newfound concern 

about HAP emissions from EGUs is not based on new and different 

assessments of the public health consequences of EGU HAP 

emissions but instead on health benefits from the reduction of 
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non-hazardous air pollutants, primarily PM, which the Agency is 

required to regulate under other provisions of the CAA. One 

commenter stated that for decades, the EPA set primary ambient 

air quality standards that protect public health with an 

adequate margin of safety, CAA section 109(b)(1), and set 

secondary standards that are [sic] “requisite to protect the 

public welfare from any known or anticipated adverse effects 

associated with the presence of such air pollutant in the 

ambient air,” CAA 109(b)(2). The commenter notes that even if 

EPA now views those past PM standards as inadequate, the EPA has 

ongoing regulatory proceedings in which it can address any 

perceived health concerns. The commenter concludes that 

regulation of EGU HAP emissions under CAA section 112 is an 

unlawful way to address those concerns. 

Response: The commenter is incorrect in its assertion that the 

Agency has consistently concluded that HAP emissions from EGUs 

do not present a hazard to public health. In the 2000 finding, 

the Agency concluded that HAP emissions from coal- and oil-fired 

EGUs do pose a hazard to public health and determined that it 

was appropriate and necessary to regulate such units under CAA 

section 112. As a result of that finding, the EPA added coaland oil-fired EGUs to the CAA section 112(c) list of source 

categories for which emission standards are to be established 
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pursuant to CAA section 112(d). Further, in support of the 

proposed rule, the EPA conducted additional extensive 

quantitative and qualitative analyses, which confirm that it 

remains appropriate and necessary to regulate EGUs under CAA 

section 112. Among other things, those analyses demonstrate that 

emissions from coal- and oil-fired EGUs continue to pose a 

hazard to public health. The commenter also fails to note that 

the EPA found that HAP emissions from EGUs pose a hazard to the 

environment as well.

The commenter seems confused about the basis for the 

Agency’s appropriate and necessary finding because it maintains 

that the EPA made the appropriate and necessary finding based on 

the health co-benefits attributable to PM reductions that will 

be achieved as a result of the Agency’s regulation of HAP 

emissions from EGUs. Nowhere in the May 2011 proposal does EPA 

state that it based the appropriate and necessary finding on 

hazards to public health attributable to PM emissions. The 

commenter’s allegation lacks foundation. The appropriate and 

necessary finding unmistakably focuses on the hazards to public 

health and hazards to the environment associated with HAP 

emissions from EGUs.

Comment: One commenter stated that CAA section 112 required EPA 

to make a risk-based determination in order to regulate HAP. 
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According to the commenter, the EPA may regulate substances 

“reasonably . . . anticipated to result in an increase in 

mortality or increase in serious illness” to a level that 

protects public health with an “ample margin of safety.”

According to the commenter, the EPA has regulated a number of 

HAP emitted from industrial source categories other than EGUs. 

As for EGUs, according to the commenter, the EPA found that 

the combustion of fossil fuels produces extremely small 

emissions of a broad variety of substances that are present in 

trace amounts in fuels and that are removed from the gas stream 

by control equipment installed to satisfy other CAA

requirements. The commenter stated that the EPA, in past 

reviews, found that these HAP emissions did not pose hazards to 

public health. See 48 FR 15076, 15085 (1983) (radionuclides). 

the commenter further stated that “[i]n the case of Hg 

specifically, the EPA found that “coal-fired power plants...do 

not emit mercury in such quantities that they are likely to 

cause ambient mercury concentration to exceed” a level that 

“will protect public health with an ample margin of safety.” 40 

FR 48297-98 (October 19, 1975) (Hg); 52 FR 8724, 8725 (March. 

19, 1987) (reaffirming Hg conclusion).

According to the commenter, in the late 1980s, the EPA was 

concerned that its prior risk assessments of individual HAP 
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emissions from fossil-fuel-fired power plants may not reflect 

the total risks posed by all HAP emitted by those sources. The 

commenter states that the EPA modeled the risks posed by all HAP 

emitted by power plants (very much like the analyses the Agency 

would conduct for the Utility Study ten years later). The 

commenter asserts that the modeling again failed to identify 

threats to public health that warranted regulation under an 

“ample margin of safety” test.

Response: The commenter’s statements concerning the pre-1990 CAA 

are not relevant to the current action. Congress enacted CAA 

section 112(n)(1) as part of the 1990 amendments to the Act. 

That provision requires, among other things, that the Agency 

evaluate the hazards to public health posed by HAP emissions 

from fossil-fuel fired EGUs. Had Congress concluded, as 

commenter appears to assert, that HAP emissions from EGUs did 

not pose a hazard to public health or the environment, it defies 

reason that Congress would have required EPA to conduct the 

three studies at issue in CAA section 112(n)(1) (titled 

“Electric utility steam generating units”) and regulate EGUs 

under section 112 if the Administrator determined in her 

discretion that it was appropriate and necessary to do so. The 

Agency complied with the statutory mandates in CAA section 
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112(n)(1) in conducting the studies and reasonably exercised its 

discretion in making the appropriate and necessary finding. 

We acknowledge that Congress treated radionuclide emissions 

from EGUs differently. For radionuclides from EGUs (and certain

other sources), Congress included CAA section 112(q)(3), which 

authorizes but does not require the Agency to maintain the 

regulations of radionuclides in effect prior to the 1990 

amendments. The fact that Congress made an exception for 

radionuclides and no other HAP from EGUs further demonstrates 

that the HAP-related actions EPA took with regard to EGUs prior 

to the 1990 amendments to the CAA are not germane. 

As for the commenter’s statements about Hg emissions from 

EGUs, we find their conclusions wholly inconsistent with CAA 

section 112(n)(1). That provision is titled “Electric utility 

steam generating units,” and it directs EPA to conduct two Hgspecific studies. See CAA sections 112(n)(1)(B) and 

112(n)(1)(C). The commenter’s suggestion that the EPA could or 

should rely on assessments of Hg from EGUs conducted prior to 

the 1990 amendments is not tenable. 

Finally, the commenter stated that the EPA conducted a risk 

assessment of all HAP from EGUs prior to the 1990 amendments and 

that the Agency did not identify any HAP that failed the “ample 

margin of safety” test. The commenter did not cite the study or 
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provide any information to support the statements so we are 

unable to respond to the alleged study directly; however, the 

risk assessments conducted in support of the appropriate and 

necessary finding, as well as the 2000 finding, demonstrate that 

HAP emissions from EGUs pose hazards to public health and the 

environment. 

b. Interpretation of “Appropriate” and “Necessary”

Comment: One commenter stated that in the preamble to the 

proposed rule, the EPA sets out its “interpretation of the 

critical terms in CAA section 112(n)(1),” arguing that this 

latest interpretation is “wholly consistent with the CAA” and 

with the Agency’s earlier “2000 finding.” See 76 FR 24976, 

24986/2 (May 3, 2011). The commenter stated that throughout the 

proposal EPA tries to suggest that it is returning to some 

earlier, “correct” interpretation of CAA section 112(n)(1) set 

forth in its 2000 action. See, e.g., 76 FR 24989/1-2 (“The 

Agency’s interpretation of the term ‘appropriate’...is wholly 

consistent with the Agency’s appropriate finding in 2000”); id. 

at 24,992/1 (“Our interpretation of the necessary finding is 

reasonable and consistent with the 2000 finding”). According to 

the commenter, the EPA did not provide in 2000 any 

interpretation of what it now characterizes as the “critical 

terms” of section 112(n)(1). See, e.g., 70 FR 15999 n.13 (the 
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“2000 finding does not provide an interpretation of the phrase 

‘after imposition of the requirements of the Act’”); id. at 

16000/2 (in 2000, the EPA “did not provide an interpretation of 

the term ‘appropriate’”); 76 FR 24992/1 (the “Agency did not 

expressly interpret the term necessary in the 2000 finding”). 

The commenter believes that for that reason alone, it is 

impossible to credit EPA’s assertion that it “appropriately 

concluded that it was appropriate and necessary to regulate 

hazardous air pollutants...from EGUs” in 2000, and that it is 

today merely “confirm[ing] that finding and conclud[ing] that it 

remains appropriate and necessary to regulate these 

emissions...”

54

Response: The commenter disagrees with certain statements in the 

preamble to the proposed rule that provide that the Agency’s 

interpretation of CAA section 112(n)(1) is reasonable and 

consistent with the 2000 finding. It is difficult to decipher 

the exact complaint that the commenter has with EPA’s proposed 

rule in this regard, but the commenter does assert that “the 

Agency did not provide in 2000 any interpretation of what it now 

characterizes as the “critical terms” of CAA section 112(n)(1).”

The commenter’s assertion lacks foundation. Although the 2000 

finding did not provide detailed interpretations of the 

regulatory terms at issue, it discussed the types of 

 

54 Id. at 24,977/3.
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considerations relevant to the appropriate and necessary 

inquiry. For example, it is clear that in 2000, the Agency was 

concerned with the then current hazards to public health and the 

environment when assessing whether it was appropriate to 

regulate EGUs under section 112.55 In addition, when evaluating 

whether it was necessary to regulate utilities, the Agency 

stated that it was necessary to regulate HAP emissions from U.S. 

EGUs under section 112 because the implementation of the other 

requirements of the Act would not adequately address the serious 

public health and environmental hazards arising from HAP 

emissions from EGUs. The Agency also specifically noted that 

“section 112 is the authority intended to address” hazards to 

public health and the environment posed by HAP emissions. Id. 

The detailed interpretation set forth in the preamble to 

the proposed rule is consistent with the 2000 finding, but EPA 

does not assert that the interpretation is in any way necessary 

to support the factual conclusions reached in the 2000 finding. 

Instead, we noted in the preamble to the proposed rule that our 

interpretation is consistent with the 2000 finding because in 

2005 we interpreted the statute in a manner that was not 

consistent with the 2000 finding. The commenter has provided no 

legal support for its position that the Agency erred in 

 

55 65 FR 79830.
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interpreting the statute in a manner that is consistent with a 

prior factual finding. 

Comment: Several commenters assert that in the 1990 amendments 

to the Clean Air Act, Congress directed the EPA to base its 

determination regarding regulation of fossil-fuel-fired 

generating units on consideration of any adverse public health 

effects identified in the study mandated by the first sentence 

of section 112(n)(1)(A) and that Congress did not dictate in 

section 112(n)(1)(A) that the EPA must regulate electric utility 

steam generating units under section 112. 

According to the commenters the sponsor of the House bill 

that became section 112(n)(1)(A) provides an explanation that 

contradicts the EPA’s approach to regulating EGUs:

“Pursuant to section 112(n), the Administrator may 

regulate fossil fuel fired electric utility steam 

generating units only if the studies described in 

section 112(n) clearly establish that emissions of any 

pollutant, or aggregate of pollutants, from such units 

cause a significant risk of serious adverse effects on 

the public health. Thus,...he may regulate only those 

units that he determines – after taking into account 

compliance with all provisions of the act and any 

other Federal, State, or local regulation and 
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voluntary emission reductions – have been demonstrated 

to cause a significant threat of serious adverse 

effects on the public health.”

136 Cong. Rec. H12,934 (daily ed. Oct. 26, 1990) 

(statement of Rep. Michael Oxley).

The commenters stated that the EPA position is premised on 

the assumption that “regulation under section 112” necessarily 

means “regulation under 112(d)” and falsely premised on the 

assumption that source categories listed by operation of section 

112(n)(1)(A) cannot be regulated differently. The commenters 

conclude that the language of section 112(n)(1)(a) reflects 

Congress’ intent that “regulation of HAP from EGUs was not 

intended to operate under section 112(d) but was instead 

intended to be tailored to the findings of the utility study 

mandated by section 112(n)(1)(A).”

Response: The commenters maintain that the Agency’s 

interpretation of CAA section 112(n)(1) is flawed in many 

respects. The primary support for one commenter’s arguments 

against EPA’s interpretation, including in the comment above, is 

legislative history in the form of statements from one 

Congressman, Representative Oxley. The Supreme Court has 

repeatedly stated that the statements of one legislator alone 

should not be given much weight. See Brock v. Pierce County, 476 
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U.S. 253, 263 (1986) (finding that “statements by individual 

legislators should not be given controlling effect, but when 

they are consistent with the statutory language and other 

legislative history, they provide evidence of Congress’

intent.”) (emphasis added) (citation omitted); Garcia, et al., 

v. U.S., 469 U.S. 70, 78 (1984), citing Zuber v. Allen, 396 U.S. 

168, 187 (1969) (reiterating its prior findings, the Court 

indicated that isolated statements “are ‘not impressive 

legislative history.’”); Weinberger, et al., v. Rossi et al., 

456 U.S. 25, 35 (declining to make a ruling based on “one 

isolated remark by a single Senator”); Consumer Product Safety 

Comm., et al. v. GTE Sylvania, Inc., et al., 447 U.S. 102, 117-

118 (1980) (declining to give much weight to isolated remarks of 

one Representative); Chrysler Corp. v. Brown, et al., 441 U.S. 

281, 311 (1979) (finding that “[t]he remarks of a single 

legislator, even the sponsor, are not controlling in analyzing 

legislative history.”); Zuber, 396 U.S. at 186 (concluding that 

“[f]loor debates reflect at best the understanding of individual 

Congressmen.”); and U.S. v. O’Brien, 391 U.S. 367, 384 (1968) 

(in evaluating the statements of a handful of Congressmen, the 

Court concluded that “[w]hat motivates one legislator to make a 

speech about a statute is not necessarily what motivates scores 

of others to enact it...”). As these cases show, the Supreme 
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Court does not give weight to the statements of an individual 

legislator, except when the statements are supported by other 

legislative history and the clear intent of the statute. The 

commenters cited no case law that would support reliance on such 

limited legislative history. 

The commenter has not cited any other legislative history 

to support Representative Oxley’s statement, and the lack of 

additional support makes the statement of little utility or 

import under the case law. In fact, there does not appear to be 

anything in the House, Senate, or Committee Reports that 

supports Oxley’s statement. The lack of support for Oxley’s 

statement in the Committee Report is particularly telling since, 

as the commenter notes, the House and Senate bills required 

different approaches to regulating EGUs under section 112, with 

the Senate bill requiring EGUs be regulated prior to the Utility 

Study. In fact, legislative statements from Senator Durenberger, 

a supporter of the Senate version, demonstrate that others would 

almost certainly not have agreed with Oxley’s interpretation. 

For example, Senator Durenberger stated, “It seems to me 

inequitable to impose a regulatory regime on every industry in 

America and then exempt one category, especially a category like 

power plants which are a significant part of the air toxics 

problem.”
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Senator Durenberger discussed the negotiations with the 

Administration and the industry push to avoid regulation, 

including industry arguments for not regulating Hg from U.S. 

EGUs: 

“The utility industry continued to adamantly oppose 

[regulation under section 112]. First, they argued 

that mercury isn’t much of an environmental problem. 

But as the evidence mounted over the summer and it 

became clear that mercury is a substantial threat to 

the health of our lakes, rivers and estuaries and that 

power plants are among the principal culprits, they 

changed their tactic. Now they are arguing that 

mercury is a global problem so severe that just 

cleaning up U.S. power plants won’t make enough of a 

difference to be worth it. They’ve gone from ‘we’re 

not a problem’ to ‘you can’t regulate us until you 

address the whole global problem.’ Recasting an issue 

that way is not new around here. So, it is not a 

surprise. But it does suggest the direction in which 

this debate will be heading in the next few years.”

136 Cong. Rec. 36062 (October 27, 1990).

Senator Durenberger also explained why the House version 

was adopted: 
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“Given that a resolution of the difficult issues in the 

conference were necessary to conclude work on this bill, 

the Senate proposed to recede to the House provision which 

was taken from the original administration bill. It 

provides for a 3-year study of utility emissions followed 

by regulation to the extent that the Administrator finds 

them necessary.”

Id.

Senator Durenberger’s statements indicate that it is 

unlikely that he would agree with Oxley’s interpretation of CAA 

section 112(n)(1), a provision that provides the Agency with 

considerable discretion, and nothing indicates that others in 

the Senate (or for that matter anyone else in the House) would 

agree with that interpretation. Given the Supreme Court’s views 

on the use of such limited legislative history, the EPA 

reasonably declined to consider (or even discuss) the 

legislative history in the preamble to the proposed rule and we 

believe it would be improper to ascribe Representative Oxley’s 

statements to the entire Congress. 

Moreover, Representative Oxley’s statement directly 

conflicts with the statutory text. Representative Oxley stated 

that “[the Administrator may regulate only those units that he 

determines – after taking into account compliance with all 
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provisions of the act and any other Federal, State, or local 

regulation and voluntary emission reductions - have been 

demonstrated to cause a significant threat of serious adverse 

effects on the public health.” 136 Cong. Rec. H12934 (daily ed. 

Oct. 26, 1990), reprinted in 1 1990 Legis. Hist. at 1416-17 

(emphasis added). However, the Utility Study required under CAA 

section 112(n)(1)(A) directs the Agency to consider the hazards 

to public health reasonably anticipated to occur after 

“imposition of the requirements of [the Clean Air Act].” EPA was 

not required to consider state or local regulations or voluntary 

emission reduction programs in the Utility Study, and that study 

is the only condition precedent to making the appropriate and 

necessary finding.56

The legislative history the commenters rely on is not 

controlling. The Agency believes that it has reasonably 

interpreted section 112(n)(1)(A), for all the reasons described 

herein and in the proposal. The commenters also cite 

Representative Oxley’s statements as support for alternative 

interpretations of CAA section 112(n)(1). We believe that any 

 

56 In addition, the EPA only considered CAA requirements in the 

Utility Study and this was the correct approach because Congress 

knew how to require consideration of non-Federal requirements 

when directing EPA to conduct a study or assessment. See CAA 

section 112(n)(5) (Congress required EPA to conduct an 

assessment of hydrogen sulfide from oil and gas extraction 

activities and provided that the assessment “shall include 

review of existing State and industry control standards, 

techniques and enforcement.”).
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arguments that rely on such limited legislative history are 

without merit. 

Comment: One commenter stated that the EPA does acknowledge 

that, in many significant respects, its new interpretation of 

CAA section 112(n)(1) “differs from that set forth” in the 

Agency’s 2005 rulemaking, but argues that its change of position 

is permissible. See 76 FR 24988/1 (“[T]o the extent our 

interpretation differs from that set forth in the 2005 Action, 

we explain the basis for that difference and why the 

interpretation, as set forth in this preamble, is reasonable.”). 

In support, commenters note that the EPA cites National Cable &

Telecommunication Ass’n v. Brand X Internet Services, 545 U.S. 

967 (2005). The commenters agree that it is true that, in Brand 

X Internet Services, the Supreme Court explained that, if an 

agency “adequately explains the reasons for a reversal of 

policy,” such change is “not invalidating,” since the “whole 

point of Chevron is to leave the discretion provided by the 

ambiguities of a statute with the implementing agency.” 545 U.S. 

at 981 (internal quotations omitted). The commenters maintain 

that all Brand X Internet Services was saying is that “[a]gency 

inconsistency is not a basis for declining to analyze the 

agency’s interpretation under the Chevron framework.” Id.
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According to the commenter, it is not enough that the EPA 

has purported to “explain” why it has abandoned the 

interpretation of CAA section 112(n)(1) adopted in 2005. The 

commenter states that under the first step of Chevron, the 

Agency’s latest interpretation must still be consistent with 

congressional intent. See Chevron v. NRDC, 467 U.S. at 842-43. 

The commenters state that under the second step of Chevron, if 

there is discretion for EPA to exercise in interpreting the 

“critical terms” of CAA section 112(n)(1), the Agency must 

properly define the range of that discretion and then act 

reasonably in exercising that discretion. See Chevron, 467 U.S. 

at 843; see also Village of Barrington, Ill. v. Surface 

Transportation Bd., No. 09-1002 (D.C. Cir. Mar. 15, 2011).The 

commenters allege that the EPA failed to properly define and 

exercise the scope of its discretion. In each instance, the 

commenter maintains that the Agency has departed from the 

correct interpretation of CAA section 112(n)(1) that it adopted 

in 2005, seizing instead upon a new approach that is contrary to 

the plain language of the CAA itself, as interpreted after 

considering the statements of Representative Oxley.

Response: The commenter appears to argue that the EPA’s 

interpretation of CAA section 112(n)(1) is not consistent with 

the plain language of the statute, implying that the statute is 
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clear and must be evaluated under step one of Chevron. See

Chevron v. NRDC, 467 U.S. 837 842-42 (1984) (finding that when 

the legislative intent is clear no additional analysis is 

required). However, as noted above, much of the commenter’s 

argument that the plain language of the statute precludes EPA’s 

interpretation is based on the unpersuasive legislative history 

discussed above. As explained in the preamble to the proposed 

rule, the statute directs the Agency to determine whether it is 

appropriate and necessary to regulate EGUs under section 112. As 

the D.C. Circuit has held, the terms “appropriate” and 

“necessary” are very broad terms. Because these terms are broad 

they are susceptible to different interpretations. We believe we 

have reasonably interpreted the appropriate and necessary 

language in section 112(n)(1)(A). To the extent that 

interpretation differs from the one set forth in 2005, we have 

fully explained the basis for such changes. See 76 FR 24986-

24993 (setting forth the Agency’s interpretation of section 

112(n)(1)).

Furthermore, we properly considered the scope of our 

discretion in interpreting the statute as explained in detail in 

the preamble to the proposed rule. We believe the interpretation 

set forth in the preamble to the proposed rule is consistent 

with the Act and, therefore, the Agency should be afforded 
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deference pursuant to National Cable & Telecommunication Ass’n 

v. Brand X Internet Services, 545 U.S. 967 (2005). 

Comment: A number of commenters agreed with the Agency’s 

interpretation of section 112(n)(1) and the terms appropriate 

and necessary. The commenters also agreed that the EPA’s 

interpretation of that provision was reasonable and consistent 

with the statute.

Response: We agree with the commenters and appreciate their 

support.

Comment: One commenter asserts that the EPA’s ultimate 

motivation for rejecting its prior interpretation of CAA section 

112(n)(1) and embracing this flawed new approach is made clear 

from the very outset of the proposal. According to the 

commenter, the EPA touts the fact that “one consequence” of the 

MACT rule would be that the “market for electricity in the U.S. 

will be more level” and “no longer skewed in favor of the higher 

polluting units that were exempted from the CAA at its inception 

on Congress’ assumption that their useful life was near an end.”

See 76 FR 24979/2. The MACT rule would “require companies to 

make a decision – control HAP emissions from virtually 

uncontrolled sources” or else “retire these sometimes 60 year 

old units and shift their emphasis to more efficient, cleaner 
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modern methods of generation, including modern coal-fired 

generation.” Id.

The commenter stated that this remarkably forthright 

statement establishes that the underlying basis for EPA’s 

proposal to regulate EGUs under CAA section 112 is not to 

address any “hazards to public health” that might be attributed 

to the emission by EGUs of HAP listed under CAA section 112(b). 

Rather, according to commenter, the EPA is utilizing the 

regulation of EGUs under CAA section 112 as a means to an 

entirely different end: to force the imposition of controls that 

will also have the result of reducing non-HAP emissions 

(primarily PM) or force the shutdown of those units for which 

the cost of such controls would be prohibitive. At the same 

time, according to commenter, the EPA tacitly acknowledges that 

it cannot hope to make out a case that the regulation of EGU HAP 

emissions is “appropriate and necessary” within the meaning of 

CAA section 112(n)(1). The commenter asserts that the only HAP 

whose health-related benefits EPA quantifies is Hg. Elsewhere, 

the commenter stated that the EPA contends there are “additional 

health and environmental effects” attributable to HAP other than 

Hg, but admits that it has “not quantified” those risks due 

supposedly to “insufficient information.” See 76 FR 24999/2. 

With respect to Hg the commenter stated that the benefits are so 
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questionable and miniscule, some $4 million to $6 million (given 

a 3 percent discount rate), that compared to the total social 

costs of the rule (i.e., nearly $11 billion) the rule cannot be 

justified were EPA properly to interpret CAA section 112(n)(1) 

and undertake the sort of regulatory analysis Congress intended. 

The commenter stated that the reason that the EPA touts in this 

rulemaking the health benefits EPA attributes to the reduction 

of non-hazardous air pollutants (again, primarily PM), the 

regulation of which is authorized under provisions of the CAA 

apart from CAA section 112, is to elide the inconvenient truth 

regarding the truly trivial nature of the benefits attributable 

to HAP regulation itself. The commenter concludes that the EPA 

distorts CAA section 112(n)(1)(A) “beyond all recognition.”

One commenter stated that the EPA is directed by CAA 

section 112(n)(1)(A) to study the “hazards to public health 

anticipated to occur as a result of emissions” by EGUs of 

“pollutants listed under subsection (b) of this section” – i.e., 

HAP and HAP alone. Thereafter, the EPA is authorized to regulate 

EGU HAP emissions if, and only if, they determine that “such 

regulation” of HAP emissions is “appropriate and necessary” to 

address the “hazards to public health” that may be attributable 

to HAP emissions. According to the commenter, by contrast, in 

this rulemaking, the EPA has seized upon the fact that the 
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control of EGU HAP emissions will also control non-HAP (such as 

PM), and then seeks to justify the regulation of HAP emissions 

based almost entirely on the health benefits of the reductions 

in non-HAP emissions that would be coincidentally achieved. The 

commenter believes that this “regulatory sleight-of-hand” runs 

afoul of congressional intent and is unlawful. 

Response: The commenter alleges that the health-related benefits 

to regulating HAP emissions from EGUs are “questionable and 

miniscule,” and that the only real benefits stem from non-HAP 

emissions, such as PM. The commenter also implies that 

regulation of HAP is nothing more than a straw man and that the 

Agency’s ultimate goal is to regulate other pollutants, and 

specifically PM. These allegations are wholly without merit. The 

Agency has conducted comprehensive technical analyses that 

confirm that HAP emissions from EGUs pose a hazard to public 

health. The analyses are discussed at length elsewhere in this 

final rule, and a review of the proposed and final rules utterly 

refutes commenter’s assertion that PM reductions form the basis 

for the appropriate and necessary finding. In addition, the 

commenter appears to ignore the Agency’s findings concerning the 

hazards to public health and the environment posed by HAP 

emissions simply because the Agency is not able to quantify many 

of the benefits associated with reductions of HAP emissions from 
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EGUs or because the estimated HAP benefits that are quantified 

are small in relation to the co-benefits achieved through 

reductions in non-HAP air pollutants, such as PM and SO2, which 

are surrogates for certain HAP. The Agency is regulating EGUs 

pursuant to section 112(d) for all of the reasons explained in 

the preamble and discussed elsewhere in this response to 

comments. The commenter fails to recognize that the statute 

neither requires a cost-benefit analysis prior to finding it 

appropriate and necessary to regulate EGUs, nor requires such 

analysis prior to setting emission standards. Indeed, Congress 

expressly precluded consideration of costs when setting MACT 

floors. As explained below, the EPA does not believe that it is 

appropriate to consider costs when determining whether to 

regulate EGUs under CAA section 112.

Comment: One commenter stated that the EPA has ignored the 

language and intent of CAA section 112(n)(1)(A), as interpreted 

based on Representative Oxley’s statements, and that the 

Agency’s interpretation of this provision violates step one of 

Chevron. Under Chevron where the “intent of Congress is clear,”

that is the “end of the matter,” for both the implementing 

agency and a reviewing court “must give effect to the 

unambiguously expressed intent of Congress.” Chevron, 467 U.S. 

at 842-43. The commenter asserts that the legislative history of 
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CAA section 112(n)(1)(A) “sheds considerable light on Congress’

unique approach to regulation of EGUs under CAA §112.” According 

to the commenter, on April 3, 1990, the Senate passed S. 1630. 

The Senate bill would have required EPA to list EGUs under CAA 

section 112(c) and to regulate them under the MACT provisions of 

CAA section 112(d). See S. 1630 section 301, 3 1990 Legis. Hist. 

at 4407. Thereafter, the House of Representatives passed a 

modified version of S. 1630 on May 23, 1990. This House version 

substantially changed the provisions of CAA section 112 as they 

applied to EGUs. See 1 1990 Legis. Hist. at 572-73. The House 

version was virtually identical to the current CAA section 

112(n)(1)(A), and was ultimately adopted by the conference 

committee, enacted by Congress and signed into law. According to 

the commenter, Congress expressly rejected the “list-under-(c)-

and-regulate-under-(d)” approach that S. 1630 would have applied 

to EGUs, and that Congress did choose to apply to other source 

categories. The commenter stated that the EPA’s interpretation 

that the Agency is “required to establish emission standards for 

EGUs consistent with the requirements set forth in section 

112(d)” (Id. at 24,993/3) fails to take the legislative history 

into account, and in a footnote, the commenter states that the 

Agency erred by not addressing the legislative history as it did 

in the 2005 action.
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Response: For the reasons stated above, we believe commenter’s 

reliance on the single statement of one legislator is flawed. In 

addition, in a footnote the commenter stated that the EPA 

recognized “that it had to address” the legislative history in 

its 2005 action, and that the EPA erred in this case because we 

did not address the legislative history. The commenter cites no 

case law to support its contention that an Agency must “address”

unpersuasive legislative history. Further, in the 2005 action, 

the EPA relegated to a footnote the Oxley statement that 

commenter relies on so heavily even though the statement 

supported the interpretation we provided in that rule. We 

recognized then what the commenter fails to recognize now, which 

is that the Agency cannot argue that the meaning of CAA section 

112(n)(1)(A) is clear based on the statements of one legislator. 

Furthermore, the Agency’s interpretation does not violate 

Chevron Step 1. The terms “appropriate” and “necessary” are 

ambiguous. The statements of a lone legislator do not transform 

those ambiguous words into a Chevron Step 1 situation.

Moreover, the commenter’s assertion that Congress 

unambiguously defined the factors to consider in making the 

appropriate determination is without merit. We fully explain in 

the preamble to the proposed rule the basis for the Agency’s 
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interpretation, and we are not revising that interpretation 

based on the comments received.

Finally, the EPA notes that the sentence concerning 

regulation under CAA section 112(d) that the commenter quotes 

from the preamble states, in full: “Congress did not exempt EGUs 

from the other requirements of section 112 and, once listed, the 

EPA is required to establish emission standards for EGUs 

consistent with the requirements set forth in section 112(d), as 

described above.” 76 FR 24993 (emphasis added). The EPA 

discusses requirements to regulate section 112(c) listed sources 

under section 112(d) in response to other comments.

c. Consideration of Both Environmental Effects and Health 

Effects from Other Sources

Comment: Several commenters stated that the EPA acts contrary to 

congressional intent when the Agency considers itself “thereby 

authorized to consider ‘environmental effects’ and the effects 

of HAP emissions from non-EGU sources, in making its 

‘appropriate and necessary’ finding under subparagraph 

(n)(1)(A).”

Commenters assert that the EPA misreads CAA section 

112(n)(1)(B) and (C) to inject environmental effects in the CAA 

section 112(n)(1)(A) determination. According to one commenter 

the plain language of CAA section 112(n)(1) establishes that 
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regulation of EGUs is to be predicated solely on “hazards to 

public health” attributable to HAP emissions. The legislative 

history providing that the EPA “may regulate [EGUs] only if the 

studies described in section 112(n) clearly establish that 

emissions of any pollutant...from such units cause a significant 

risk of serious adverse risk to the public health” confirms that 

plain language. See Oxley Statement at 1416-17. The commenter 

further stated that nothing on the face of CAA section 

112(n)(1)(A) indicates that Congress intended that the EPA 

should (or must) take into account any additional information 

that might be developed through the other studies mentioned in 

subparagraphs (n)(1)(B) and (C) (i.e., the Mercury Study57 and 

the NAS Study58), such as HAP emissions from non-EGU sources. The 

commenter also identified other provisions of section 112 that 

specifically require consideration of environmental effects and 

states that Congress would have requires such consideration in 

CAA section 112(n)(1) if it had wanted EPA to consider 

environmental effects.

The commenter makes a related assertion that the EPA acts 

contrary to congressional intent by assuming authority to assess 

the “‘hazard to public health or the environment [from] HAP 

emissions from EGUs alone’ or the ‘result of HAP emissions from 

 

57 U.S. EPA. 1997. Mercury Study Report to Congress. EPA–452/R–

97–003. December.

58 NAS, 2000.
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EGUs in conjunction with HAP emissions from other sources’”

(citing 76 Fed. Reg. at 24,988/1). According to the commenter, 

the only evident basis for the Agency’s interpretation that, in 

making its “appropriate and necessary” finding, the EPA can (and 

should) take into account HAP emissions from sources other than

EGUs, is that the Mercury Study authorized by CAA 112(n)(1)(B) 

references “mercury emissions from . . . municipal waste 

combustion units, and other sources, including area sources,” in 

addition to EGUs. The commenter asserts, however, that 

subparagraph (n)(1)(A) identifies the Utility Study as the sole 

study to inform EPA’s “appropriate and necessary” finding. The 

commenter states that if Congress had intended that the EPA take 

into account information developed through the Mercury Study, 

Congress “would not have specified that the EPA was to predicate 

its ‘appropriate and necessary’ finding on the ‘results of the 

study required by this subparagraph’ (n)(1)(A).”

Commenter also cites to a number of other section 112 

provisions that expressly address environmental effects and the 

commenter states the only conclusion to draw from the inclusion 

in those provisions and the absence of such language in section 

112(n)(1)(A) is that Congress intended public health to be the 

only basis for the appropriate and necessary finding.
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Response: The commenter again relies in part on the statements 

of one legislator to attack EPA’s reasoned interpretation of an 

ambiguous statute. To the extent the commenter’s arguments rely 

on this limited evidence, we refer to the response above. As we 

stated above, CAA section 112(n)(1) is an ambiguous statutory 

provision; thus, the EPA’s interpretation, not commenter’s, is 

entitled to considerable deference if it is a reasonable reading 

of the statute. Chevron, 467 U.S. at 843-44. For the reasons 

described herein and in the proposal, we believe that we have 

reasonably interpreted the statutory terms at issue here. The 

Agency directs attention to section III.A. of the proposed rule, 

which includes a thorough discussion of the Agency’s 

interpretation of the relevant statutory terms. To the extent 

the commenters disagree with EPA’s interpretations, the EPA 

refers back to its discussion in the proposal and responds to 

the comments as follows.

The commenter appears to maintain that the EPA must 

interpret the scope of the appropriate and necessary finding 

solely in the context of the CAA section 112(n)(1)(A) Utility 

Study, such that only hazards to public health and only EGU HAP 

emissions may be considered. The commenter incorrectly conflates 

the requirements for the Utility Study with the requirement to 

regulate EGUs under CAA section 112 if EPA determines it is 
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appropriate and necessary to do so. The commenter concedes that 

the Agency may consider information other than that contained in 

the Utility Study, but only to the extent it relates 

specifically to hazards to public health directly attributable 

to HAP emissions from EGUs. We agree that we may consider 

additional information other than that contained in the Utility 

Study, as we stated in the preamble to the proposed rule, 

because courts do not interpret phrases like “after considering 

the results of” in a manner that precludes the consideration of 

other information. See United States v. United Technologies 

Corp., 985 F.2d 1148, 1158 (2nd Cir. 1993) (“based upon” does not 

mean “solely)59; see also 76 FR 24988. We further explained in 

the preamble to the proposed rule that it was reasonable to 

interpret the scope of the appropriate and necessary finding in 

the context of all three studies required under CAA section 

112(n)(1) because the provision is title “Electric utility steam 

generating units.”

60 The commenter has provided little more than 

 

59 Several commenters have taken issue with our citation to 

United States v. United Technologies Corp. because the language 

at issue in that case was “based upon” and the language of 

section 112(n)(1)(A) is “after considering the results of.” We 

believe that, if anything, “based upon” is more prescriptive 

than “after considering the results of” such that the case 

supports the Agency’s interpretation that additional information 

other than the Utility Study may be considered in making the 

appropriate and necessary finding. 

60 76 FR 24986-87.
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unpersuasive legislative history to support its restrictive 

interpretation of our authority. Id. 

The commenter also argues that the statute clearly 

prohibits the Agency from considering adverse environmental 

effects or the cumulative effects of HAP emissions from EGUs and 

other sources based on its claim that the statute is clear when 

one properly considers the legislative history. Again, the 

commenter has provided no support for its contention other than 

the statements of one Representative and the improper conflation 

of the CAA section 112(n)(1)(A) direction on the conduct of the 

Utility Study and the appropriate and necessary finding. 

Congress left it to the Agency to determine whether it is 

appropriate and necessary to regulate EGUs under CAA section 112 

and the statute does not limit the Agency to considering only 

hazards to public health and only harms directly and solely 

attributable to EGUs. 

The commenter stated that Congress specifically told EPA 

when it wanted EPA to consider adverse environmental effects in 

CAA section 112 and cites to several provisions of the Act that 

require consideration of adverse environmental effects. The 

commenter ignores CAA section 112(n)(1)(B), which directs the 

Agency to consider adverse environmental effect. In any event, 

even were we to view section 112(n)(1)(A) in isolation, as the 
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commenter suggests, we still maintain that we can consider 

adverse environmental effects under 112(n)(1)(A). Nothing in 

section 112(n)(1)(A) precludes consideration of environmental 

effects. Congress required the Agency to assess whether it is 

appropriate and necessary to regulate EGUs under section 112. We 

believe that adverse environmental effects can be considered in 

the appropriate analysis. Congress specifically directed the 

Agency to consider adverse environmental effects when delisting 

source categories pursuant to section 112(c)(9), and thus we 

believe it is reasonable to consider such effects when 

determining whether it is appropriate to regulate such units 

under section 112, especially given that Congress did not limit 

our appropriate and necessary inquiry to the Utility Study. See 

CAA section 112(c)(9)(B)(ii).

Moreover, the other provisions of CAA section 112 that 

specifically discuss environmental effects have purposes that 

are distinguishable from CAA section 112(n)(1), and we do not 

believe one can reasonably draw the conclusion that the 

commenter does when comparing those provisions to CAA section 

112(n)(1)(A). The lack of a requirement to consider 

environmental effects in CAA section 112(n)(1)(A) does not 

equate to a prohibition on the consideration of environmental 

effects as the commenter concludes. The EPA maintains that it 
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reasonably concluded that we should protect against identified 

or potential adverse environmental effects absent clear 

direction to the contrary. 

Concerning the consideration of the cumulative effect of 

HAP emissions from EGUs and other sources, we provided a 

reasonable interpretation of the statute and noted that our 

interpretation, unlike commenters, does not “ignore the manner 

in which public health and the environment are affected by air 

pollution. An individual that suffers adverse health effects as 

the result of the combined HAP emissions from EGUs and other 

sources is harmed, irrespective of whether HAP emissions from 

EGUs alone would cause the harm.”

61

d. Finding for all HAP to be Regulated

Comment: Several commenters stated that for those EGU HAP for 

which the Agency makes no CAA section 112(n)(1)(A) 

determination, their regulation under CAA section 112 is not 

authorized. For example, one commenter maintains that the Agency 

could regulate HAP emissions from EGUs under CAA section 112(n). 

Accordingly, to the extent that the EPA reads CAA section 112, 

as construed by National Lime Ass’n, as compelling it to 

regulate all HAP emitted by EGUs, should the Agency make an 

“appropriate and necessary” determination under CAA section 

112(n)(1)(A) with respect to a single HAP (e.g., Hg), the EPA 

 

61 76 FR 24988.
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stands poised to commit a fundamental legal error that will 

condemn the final rule on review. Cf., e.g., PDK Laboratories, 

Inc., 362 F.3d at 797-98; Holland v. Nat’l Mining Ass’n, 309 

F.3d at 817 (where an agency applies a Court of Appeals 

“interpretation...because it believed that it had no choice” and 

that it “was effectively ‘coerced’ to do so,” then the agency 

“cannot be deemed to have exercised its reasoned judgment”).

Response: We do not agree with the commenter’s assertion that 

Congress intended EPA to regulate only those EGU HAP emissions 

for which an appropriate and necessary finding is made, and the 

commenter has cited no provision of the statute that states a 

contrary position. The EPA reasonably concluded that we must 

find it “appropriate” to regulate EGUs under CAA section 112 if 

we determine that a single HAP emitted from EGUs poses a hazard 

to public health or the environment. If we also find that 

regulation is necessary, the Agency is authorized to list EGUs 

pursuant to CAA section 112(c) because listing is the logical 

first step in regulating source categories that satisfy the 

statutory criteria for listing under the statutory framework of 

CAA section 112. See New Jersey, 517 F.3d at 582 (stating that 

“[s]ection 112(n)(1) governs how the Administrator decides 

whether to list EGUs...”). As we noted in the preamble to the 

proposed rule, D.C. Circuit precedent requires the Agency to 
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regulate all HAP from major sources of HAP emissions once a 

source category is added to the list of categories under CAA 

section 112(c). National Lime Ass’n v. EPA, 233 F.3d 625, 633 

(D.C. Cir. 2000). 76 FR 24989. 

The commenter does not explain its issues with our 

interpretation of how regulation under section 112 works – i.e. 

making a determination that a source category should be listed 

under CAA section 112(c), listing the source category under CAA 

section 112(c), regulating the source category under CAA section 

112(d), and conducting the residual risk review for sources 

subject to MACT standards pursuant to CAA section 112(f). 

Instead, it asserts that our decision is flawed because the 

interpretation we provided does not account for all the 

alternatives for regulating EGUs under section 112, and that we 

have not properly exercised our discretion leading to a fatal 

flaw in our rulemaking. 

The commenter also ignores the language of section 

112(n)(1)(A). As explained in the proposed rule, the use of the 

terms section, subsection, and subparagraph in section 

112(n)(1)(A) demonstrates that Congress was consciously 

distinguishing the various provisions of section 112 in 

directing EPA’s action under section 112(n)(1)(A). Congress 

directed the Agency to regulate utilities “under this section,”
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not “under this subparagraph,” and accordingly EGUs should be 

regulated under section 112 in the same manner as other 

categories for which the statute requires regulation.

Furthermore, the D.C. Circuit Court found that section 112(n)(1) 

“governs how the Administrator decides whether to list EGUs” and 

that once listed, EGUs are subject to the requirements of 

section 112. New Jersey, 517 F.3d at 583. Indeed, the D.C. 

Circuit Court expressly noted that “where Congress wished to 

exempt EGUs from specific requirements of section 112, it said 

so explicitly,” noting that “section 112(c)(6) expressly exempts 

EGUs from the strict deadlines imposed on other sources of 

certain pollutants.” Id. Congress did not exempt EGUs from the 

other requirements of section 112, and once listed, the EPA is 

reasonably regulating EGUs pursuant to the standard-setting 

provisions in section 112(d), as it does for all other listed 

source categories.

The commenter provided no alternative theory for regulating 

EGUs under CAA section 112, other than to state that the EPA 

could regulate under CAA section 112(n)(1). However, even 

assuming for the sake of argument, that we could issue standards 

pursuant to CAA section 112(n)(1), we would decline to do 

because there is nothing in section 112(n)(1)(A) that provides 

any guidance as to how such standards should be developed. Any 
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mechanism we devised, absent explicit statutory support, would 

likely receive less deference than a CAA section 112(d) standard 

issued in the same manner in which the Agency issues standards 

for other listed source categories. We would also decline to 

establish standards under section 112(n)(1) because Congress did 

provide a mechanism under CAA sections 112(d) and (f) for 

establishing emission standards for HAP emissions from 

stationary sources and it is reasonable to use that mechanism to 

regulate HAP emissions from EGUs. 

e. Considering Costs in Finding

Comment: Several commenters assert that the EPA must consider 

costs in assessing whether regulation of EGUs is appropriate 

under CAA section 112(n)(1)(A). Commenters posit that the EPA’s 

position that “the term ‘appropriate’ . . . does not allow for 

the consideration of costs in assessing whether hazards . . . 

are reasonably anticipated to occur based on EGU emissions,” 76 

Fed. Reg. at 24,989/1, does not withstand scrutiny. According to 

the commenters, the treatment of “costs” under section 112(c) 

does not support the Agency’s position, and the process by which 

sources may be “delisted” under section 112(c)(9), including no 

consideration of costs, sheds no light on the circumstances 

under which it may be “appropriate” to regulate EGUs under 

section 112(n)(1)(A). 
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Commenters characterize as “unintelligible” the EPA’s 

position that it is “reasonable to conclude that costs may not 

be considered in determining whether to regulate EGUs” when 

“hazards to public health and the environmental are at issue 

(citing 76 Fed. Reg. at 24,989/1). “Two commenters stated that a 

natural reading of the term “appropriate” would include the 

consideration of costs. According to the commenters, something 

may be found to be “appropriate” where it is “specially 

suitable,” “fit,” or “proper.” See Webster’s Third New 

International Dictionary at 106 (1993). The term “appropriate”

carries with it the connotation of something that is “suitable 

or proper in the circumstances.” See New Oxford American 

Dictionary (2d Ed. 2005). Considering the costs associated with 

undertaking a particular action is inextricably linked with any 

determination as to whether that action is “specially suitable”

or “proper in the circumstances.” One commenter notes that in 

2005 (70 FR 15994, 16000; March 29, 2005) the EPA used the 

dictionary definition of “appropriate,” as being “especially 

suitable or compatible” and that it would be difficult to fathom 

how a regulatory program could be either “suitable” or 

“compatible” for a given public health objective without 

consideration of cost.
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One commenter asserts that on the face of CAA section 

112(n)(1)(A), it is clear that the EPA is expected to consider 

costs. According to the commenter, that Congress intended that 

the EPA investigate and consider “alternative control 

strategies” for emissions as part of the section 112 (n)(1) 

Utility Study when making the “appropriate and necessary”

determination refutes the notion that the Agency can, and indeed 

must, disregard the cost of regulation in making that 

determination, because the cost of a given emission “control 

strategy” is a central factor in any evaluation of “alternative”

controls. 

Further, according to commenters, it is well-settled that 

CAA regulatory provisions should be read with a presumption in

favor of considering costs (citing Michigan v. EPA, 213 F.3d 

663, 678 (D.C. Cir. 2000)), and the legislative history of 

section 112(n)(1)(A) confirms that Congress intended EPA to 

consider costs (citing Oxley Statement at 1417).

Commenters also assert that the EPA falsely represents that 

it “did not consider costs when making the “appropriate”

determination in the EPA’s December 2000 notice ( 76 Fed. Reg. 

at 24,989/2).

Response: The commenters first take issue with EPA’s explanation 

of why the Agency determined that costs should not be considered 
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in making the appropriate determination. What commenters do not 

identify is an express statutory requirement that the Agency 

consider costs in making the appropriate determination. Congress 

treated the regulation of HAP emissions differently in the 1990 

CAA amendments because the Agency was not acting quickly enough 

to address these air pollutants with the potential to adversely 

affect human health and the environment. See New Jersey, 517 

F.3d at 578. Specifically, following the 1990 CAA amendments, 

the CAA required the Agency to list source categories and 

nothing in the statute required us to consider costs in those 

listing decision, and we have not done so when listing other 

source categories. Thus, it is reasonable to make the listing 

decision, including the appropriate determination, without 

considering costs. 

The commenters next argue that the Agency is compelled by 

the statute to consider costs based on a dictionary definition 

of “appropriate” and the CAA section 112(n)(1)(A) direction to 

consider alternative control strategies for regulating HAP 

emissions in the Utility Study. 

Concerning the definition of “appropriate”, commenters 

stated: 

“Not only is it “reasonable” for EPA to consider costs 

in determining whether it is “appropriate” to regulate 
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EGU HAP emissions, a natural reading of the term 

indicates that excluding the consideration of costs 

would be entirely unreasonable. Something may be found 

to be “appropriate” where it is “specially suitable,”

“fit,” or “proper.” See Webster’s Third New 

International Dictionary at 106 (1993). The term 

“appropriate” carries with it the connotation of 

something that is “suitable or proper in the 

circumstances.” See New Oxford American Dictionary (2d 

Ed. 2005) at 76. Considering the costs associated with 

undertaking a particular action is inextricably linked 

with any determination as to whether that action is 

“specially suitable” or “proper in the circumstances.”

The EPA believes the definition of “appropriate” that the 

commenters provide wholly support its interpretation and nothing 

about the definition compels a consideration of costs. It is 

appropriate to regulate EGUs under CAA section 112 because EPA 

has determined that HAP emissions from EGUs pose hazards to 

public health and the environment, and section 112 is “specially 

suitable” for regulating HAP emissions, and Congress 

specifically designated CAA section 112 as the “proper”

authority for regulating HAP emissions from stationary sources, 

including EGUs. Section 112 of the CAA is “suitable [and] proper 
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in the circumstances” because EPA has identified a hazard to 

public health and the environment from HAP emissions from EGUs 

and Congress directed the Agency to regulate HAP emissions from 

EGUs under that provision if we make such a finding. Cost does 

not have to be read into the definition of “appropriate” as 

commenter suggests. In addition, as stated elsewhere in response 

to comments, the Agency does not consider costs in any listing 

or delisting determinations, and the EPA maintains that it is 

reasonable to assess whether to list EGUs (i.e. the appropriate 

and necessary finding) without considering costs.

The commenters’ argument that costs must be considered 

based on the CAA section 112(n)(1)(A) requirement to “develop 

and describe alternative control strategies” in the Utility 

Study is equally flawed. The argument is flawed because Congress 

did not direct the Agency to consider in the Utility Study the 

costs of the controls when evaluating the alternative control 

strategies. In addition, the EPA did not consider the costs of 

the alternative controls in the Utility Study, as implied by the 

commenter. Thus, even viewing section 112(n)(1)(A) in isolation, 

there is nothing in that section that compels EPA to consider 

costs. For the reasons described herein, we do not believe that 

it is appropriate to consider costs in determining whether to 

regulate EGUs under section 112.
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Additionally, one commenter attempts to refute EPA’s 

statement in the preamble to the proposed rule that the EPA did 

not consider costs in the 2000 finding by pointing to the only 

two mentions of cost in that notice. However, the EPA did not 

say that costs were not mentioned in the 2000 finding and a 

review of the regulatory finding will show that costs were not 

considered in the regulatory finding. 65 FR 79830 (December 20, 

2000) (“Section III. What is EPA’s Regulatory Finding?”).

f. Considering requirements of the CAA in “Necessary”

Comment: Several commenters disagree with EPA’s position that it 

need consider “only those requirements that Congress directly 

imposed on EGUs through the CAA as amended in 1990,” for which 

“EPA could reasonably predict HAP emission reductions at the 

time of the Utility Study.” According to the commenters, the 

statutory language of CAA section 112(n)(1) requires that the 

EPA consider the scope and effect of EGU HAP emissions after the 

imposition of all of the “requirements” of the CAA, not just the 

Acid Rain program. The commenter maintains that it would have 

been easy enough for Congress in subparagraph 112(n)(1)(A) to 

specify “after imposition of the requirements of Title IV of 

this chapter,” but Congress did not. The commenters further add 

that the legislative history confirms that Congress meant 

something much broader than that, providing that the EPA is 
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authorized to regulate EGUs under CAA section 112 only after 

“taking into account compliance with all provisions of the act 

and any other Federal, State, or local regulation and voluntary 

emission reductions.” The commenters stated that the CAA’s 

“requirements” include the submission by states of ozone and 

fine PM attainment demonstrations, as well as SIP provisions 

needed to reach attainment of the NAAQS because such provisions 

could include controls on EGUs to reduce SO2 and NOx, which 

controls could also result in a reduction in Hg emissions.

Response: The commenter’s characterization of the facts is 

flawed and its reliance on legislative history that is in direct 

conflict with the express terms of the statute is unpersuasive. 

On the facts, the EPA explained in the preamble to the 

proposed rule its interpretation of the phrase “after imposition 

of the requirements of [the Act]” as it related to the conduct 

of the Utility Study.62 We reasonably concluded that, since 

Congress only provided 3 years after enactment to conduct the 

study, the phrase referred to requirements that were directly 

imposed on EGUs through the CAA amendments and for which the 

Agency could reasonably predict co-benefit HAP emission 

reductions. Id. The EPA did not state that the phrase only 

applied to the Acid Rain program, as commenter asserts, and the 

Utility Study in fact discussed other regulations, including the 

 

62 76 FR 24990.
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NSPS for EGUs and revised NAAQS. With regard to the latter, the 

EPA ultimately determined that it could not sufficiently 

quantify the reductions that might be attributable to the NAAQS 

because states are tasked with implementing those standards. See

Utility Study, pages ES-25, 1-3, 2-32. Conversely, commenter’s 

position is that the EPA must consider implementation of all the 

requirements of the CAA, but it does not indicate how in 

conducting the Utility Study the Agency could have possibly 

considered co-benefit HAP reductions attributable to all future 

CAA requirements. The Agency appropriately considered the other 

requirements of the Act in the Utility Study and considered 

those requirements in determining that it was necessary to 

regulate coal- and oil-fired EGUs in December 2000.

Although not required, the Agency in the preamble to the 

proposed rule conducted further analyses in support of the 2000 

finding. In doing so, we considered a number of requirements 

that far exceed what Congress contemplated when enacting CAA 

section 112(n)(1)(A) ), and our analyses still show that it 

remains necessary to regulate coal- and oil-fired EGUs under 

section 112. 76 FR 24991. 

We maintain that we have reasonably interpreted the 

requirement to consider the hazards to public health and the 

environment reasonably anticipated to occur after imposition of 
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the requirements of the Act as explained in the preamble to the 

proposed rule.63 In addition, as stated above, we also believe it 

would be reasonable to find it necessary to regulate HAP 

emissions from EGUs based on our finding that such emissions 

pose a hazard to public health and the environment today without 

considering future reductions that we currently project to occur 

as the result of imposition of CAA requirements that are not yet 

effective (e.g., CSAPR). 

Moreover, Representative Oxley’s statement cited by the 

commenter is not consistent with the express terms of CAA 

section 112(n)(1)(A) on this issue. Representative Oxley stated 

that the EPA was to take “into account compliance with all the 

provisions of the act and any other Federal, State, or local 

regulation and voluntary emission reductions,” but CAA section 

112(n)(1)(A) directs the Agency to consider “imposition of the 

requirements of this chapter,” which means the CAA. The Agency 

reasonably focused on the requirements of the Clean Air Act, 

which are federally enforceable, and declined to include 

potential future reductions that may be attributable to 

voluntary emission reduction programs or state and local 

regulations that have no basis in the Clean Air Act and are not 

federally enforceable. In addition to the statutory direction 

not to consider such requirements, the EPA believes it is 

 

63 76 FR 24990.
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reasonable not to include potential reductions attributable to 

such requirements because the Agency cannot assure that such 

requirements and the attendant HAP reductions will remain absent 

regulation under section 112. Finally, the commenter implies 

that EPA’s position is that the Agency will only consider 

requirements of the Act that directly regulate HAP emissions. 

The EPA never stated or suggested that interpretation and a fair 

reading of the proposed rule will demonstrate that EPA 

considered requirements that achieve co-benefit HAP emission 

reductions, for example the Transport Rule (known as CSAPR).

Comment: One commenter stated that, under CAA section 112, 

regulating EGUs is permissible only insofar as it is focused, 

targeted, and predicated on concrete findings by the Agency that 

such regulation is indeed “necessary.” According to the 

commenter, the EPA construes CAA section 112(n)(1)(A) as 

permitting it to find that it is “necessary” to regulate EGUs 

even where the Agency does not actually know whether it is 

“necessary” to regulate EGUs. Citing the D.C. Circuit, the EPA 

suggests that “‘there are many situations in which the use of 

the word ‘necessary,’ in context, means something that is done, 

regardless of whether it is indispensible,’” in order to 

“‘achieve a particular end.’” 76 FR 24990, quoting Cellular 

Telecommunications v. FCC, 330 F.3d 502, 510 (D.C. Cir. 2003). 
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The commenter stated that in the “context” of CAA section 

112(n)(1)(A), as informed by the relevant legislative history 

from Representative Oxley, it is clear that regulation of EGU 

HAP emissions can be considered “necessary” only if EPA were to 

“clearly establish” that such regulation was effectively 

“indispensible” to address the identified harm. As EPA concedes 

that it has made no such determination here, its proposal is 

fatally flawed for that reason alone.

The commenter further asserts that the EPA erred when it 

concluded that it may “‘determine it is necessary to regulate 

under section 112’ when the Agency is ‘uncertain whether 

imposition of the requirements of the CAA will address the 

identified hazards’” (citing 76 Fed. Reg. at 24,991/3). 

According to the commenter, the EPA “cannot take refuge in its 

own ‘uncertainty’ to support a finding that it is ‘necessary’ to 

regulate EGUs under section 112, and the Act precludes the EPA 

from “‘err[ing] on the side of regulation’” in face of 

uncertainty (id.). The commenter also implies that the finding 

was based on non-HAP emissions.

Response: The commenter again relies on the legislative 

statements of one Representative and asserts that the statements 

are controlling. The EPA disagrees with commenter and maintains 

that its interpretation of the term “necessary” is reasonable. 
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76 FR 24990-92 (Section III.A.2.b of the preamble to the 

proposed rule contains the EPA’s interpretation of the term 

“necessary”.) 76 FR 24990-92 (Section III.A.2.b of the proposed 

rule contains EPA’s interpretation of the term “necessary”.) The 

commenter also, in a footnote, implies that EPA based the 

appropriate and necessary finding on non-HAP air pollution. The 

commenter is wrong as explained in more detail above.

As an initial matter, this comment is only addressing one 

aspect of the Agency’s interpretation of the term necessary. As 

EPA stated at proposal: 

“If we determine that the imposition of the 

requirements of the CAA will not address the 

identified hazards, EPA must find it necessary to 

regulate EGUs under section 112. Section 112 is the 

authority Congress provided to address hazards to 

public health and the environment posed by HAP 

emissions and section 112(n)(1)(A) requires the Agency 

to regulate under section 112 if we find regulation is 

“appropriate and necessary.” If we conclude that HAP 

emissions from EGUs pose a hazard today, such that it 

is appropriate, and we further conclude based on our 

scientific and technical expertise that the identified 

hazards will not be resolved through imposition of the 
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requirements of the CAA, we believe there is no 

justification in the statute to conclude that it is 

not necessary to regulate EGUs under section 112.”

76 FR 24991.

The EPA has determined that the imposition of the 

requirements of the CAA will not address the hazards to public 

health or hazards to the environment that EPA has identified; 

therefore, it is necessary to regulate EGUs under CAA section 

112. 

The EPA further interpreted the statute to allow the Agency 

to find that it is necessary to regulate EGUs under other 

circumstances, and it is with one of our additional 

interpretations that commenter takes issue. Specifically, the 

commenter argues that EPA’s interpretation authorizes the Agency 

to find it necessary to regulate EGUs when we are uncertain it 

is necessary, but that misconstrues our interpretation and the 

record. At proposal, the EPA stated:

“In addition, we may determine it is necessary to 

regulate under section 112 even if we are uncertain 

whether the imposition of the requirements of the CAA 

will address the identified hazards. Congress left it 

to EPA to determine whether regulation of EGUs under 

section 112 is necessary. We believe it is reasonable 
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to err on the side of regulation of such highly toxic 

pollutants in the face of uncertainty. Further, if we 

are unsure whether the other requirements of the CAA 

will address an identified hazard, it is reasonable to 

exercise our discretion in a manner that assures 

adequate protection of public health and the 

environment. Moreover, we must be particularly mindful 

of CAA regulations we include in our modeled estimates 

of future emissions if they are not final or are still 

subject to judicial review ([e.g.], the Transport 

Rule). If such rules are either not finalized or 

upheld by the Courts, the level of risk would 

potentially increase.”Id.

The CAA requires EPA to exercise its discretion in 

determining whether regulation under section 112 is necessary, 

and the D.C. Circuit has stated that “there are many situations 

in which the use of the word ‘necessary,’ in context, means 

something that is done, regardless of whether it is 

indispensible, to achieve a particular end.” See Cellular 

Telecommunications & Internet Association, et al. v. FCC, 330 

F.3d 502, 510 (D.C. Cir. 2003). The EPA’s interpretation of 

“necessary” is reasonable in the context of CAA section 

112(n)(1)(A).
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The commenter stated that EPA concedes that the Agency has 

not “clearly established” that regulation of HAP emissions under 

CAA section 112 is “indispensible.” The EPA has conceded nothing 

but, more importantly, the supposed standard that the commenter 

presents for evaluating whether it is necessary to regulate HAP 

emissions from EGUs is not required by the statute. Even the 

limited legislative history on which the commenter incorrectly 

relies does not espouse such a standard. The commenter 

specifically takes issue with EPA’s statement that the Agency 

may find it is necessary to regulate EGUs under CAA section 112 

if we are “uncertain whether imposition of the other 

requirements of the CAA will sufficiently address the identified 

hazards.” 76 FR at 24990. The commenter has again misinterpreted 

the Agency’s position by stating that “EPA construes CAA section 

112(n)(1)(A) as permitting it to find that it is “necessary” to 

regulate EGUs even where the Agency does not actually know 

whether it is “necessary” to regulate EGUs.” Instead, the EPA 

maintains that it may be necessary to regulate EGUs under CAA 

section 112 if we identify a hazard to public health or the 

environment that is appropriate to regulate today and our 

projections into the future do not clearly establish that the 

imposition of the requirements of the CAA will address the 

identified hazard in the future. Making a prediction about 
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future emission reductions from a source category is difficult 

for statutory provisions that do not mandate direct control of 

the given source category or pollutants of concern. We maintain 

that erring on the side of caution is appropriate when the 

protection of public health and the environment from HAP 

emissions is not assured based on our modeling of future 

emissions. 

Furthermore, as we stated in the preamble to the proposed 

rule, we believe it would be reasonable to find it appropriate 

and necessary to regulate EGUs under section 112 today based on 

a determination that HAP emissions from EGUs pose a hazard to 

public health and the environment without considering future HAP 

emission reductions. 76 FR 24991, n.14. We maintain this is 

reasonable because “Congress could not have contemplated in 1990 

that EPA would have failed in 2011 to have regulated HAP 

emissions from EGU’s where hazards to public health and the 

environment remain.” Id. The phrase “after imposition of the 

requirements of [the Act]” as contemplated CAA section 

112(n)(1)(A) could be read to apply only to those requirements 

clearly and directly applicable to EGUs under the 1990 CAA 

amendments, all of which have been implemented and still hazards 

to public health and the environment from HAP emissions from 

EGUs remain.
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g. Listing EGUs under 112

Comment: One commenter stated that even if EPA were to establish 

under CAA section 112(n)(1)(A) that it is “appropriate and 

necessary” to regulate HAP emissions from EGUs, regulating those 

emissions in the form of a MACT standard established pursuant to 

CAA section 112(d) is contrary to the plain language of the Act. 

According to the commenter, if EPA proceeds to finalize the 

proposal and adopts such a standard, the rule will for this 

reason alone be “dead-on-arrival”. According to the commenter, 

the EPA apparently believes that its only option in regulating 

EGU HAP emissions is establishing a MACT standard under CAA 

section 112(d). In the preamble to its proposal, the commenter 

states that EPA contends that, “once the appropriate and 

necessary finding is made,” EGUs are then “subject to section 

112 in the same manner as other sources of HAP emissions” –

i.e., by “listing” EGUs under CAA section 112(c) and adopting a 

MACT standard under CAA section 112(d). See 76 FR 24993/2 

(emphasis added). The commenter further stated that, given that 

Congress “directed the Agency to regulate utilities ‘under this 

section’ [i.e., CAA section 112],” EPA continues, it follows 

that “EGUs should be regulated in the same manner as other 

categories for which the statute requires regulation.” Id. 

(emphasis added). The commenter asserts that as EPA sees it, 
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because “Congress did not exempt EGUs from the other 

requirements of section 112,” once EGUs were “listed” under CAA 

section 112(c), the Agency was “required to establish emission 

standards for EGUs consistent with the requirements set forth in 

section 112(d).” Id. at 24,993/3 (emphasis added).

The commenter stated that, in support of this reading of 

the CAA, the EPA invokes the decision of the U.S. Court of 

Appeals for the D.C. Circuit in New Jersey v. EPA, 517 F.3d 574 

(D.C. Cir. 2008). The commenter further alleged that, according 

to EPA, the D.C. Circuit has “already held that section 

112(n)(1) ‘governs how the Administrator decides whether to list 

EGUs.’” See 76 FR 24993/2-3, quoting 517 F.3d at 583. The 

commenter stated that EPA construes that holding as indicating 

that, “once listed, EGUs are subject to the requirements of 

section 112” – including, the EPA presumes, CAA section 112(d). 

Id. The commenter stated that elsewhere, the EPA construes CAA 

section 112(n)(1) (A) as “govern[ing] how the Administrator 

decides whether to list EGUs for regulation under section 112,”

and quotes the D.C. Circuit’s observation in New Jersey that 

“Section 112(n)(1) governs how the Administrator decides whether 

to list EGUs; it says nothing about delisting EGUs.” See 76 FR 

24981/2, quoting 517 F.2d at 582.
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The commenter asserts that EPA misinterprets the “under 

this section” language of CAA section 112(n)(1); overstates the 

significance of the New Jersey decision; and, as a consequence, 

misapprehends the scope of its own discretion to formulate 

regulatory standards for EGUs under CAA section 112. In light of 

these errors, the commenter maintains that EPA should withdraw 

the proposed MACT rule.

One commenter stated that if Congress had intended that EPA 

regulate EGU HAP emissions only through a MACT standard, 

Congress could have – and presumably would have – directed the 

Agency to regulate EGU emissions “under CAA section 112(d).”

Thus, the commenter maintained that EPA’s authority to regulate 

EGU HAP emissions is not derived from any particular subsection 

of CAA section 112. Rather, the commenter stated that EPA is 

authorized to regulate “under this section” – i.e., CAA section 

112 generally – as may be “appropriate and necessary.” The 

commenter stated that there is nothing on the face of CAA 

section 112(n)(1)(A) that specifies that regulation of EGUs must 

occur under CAA section 112(d). To the contrary, according to 

the commenter, a plain reading of CAA section 112(n)(1)(A), as 

interpreted based on the Oxley statement, indicates that 

establishing a MACT standard for EGUs under CAA section 112(d) 

is not what Congress had in mind at all.
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Response: We do not agree with the commenter. The EPA 

interpreted CAA section 112(n)(1)(A) in a manner that gives 

meaning to all the words used in the provision. See NRDC v. EPA, 

489 F.3d 1364, 1373 (D.C. Cir. 2007) (admonishing EPA for an 

interpretation of CAA section 112(c)(9) that ignored certain 

words and the context in which they were used. The Court stated 

that “EPA’s interpretation would make the words redundant and 

one of them ‘mere surplusage,’ which is inconsistent with a 

court’s duty to give meaning to each word used by Congress.”) 

(citing TRW Inc. v. Andrews, 534 U.S. 19, 31, 122 S. Ct. 441, 

151 L. Ed. 2d 339 (2001)). Specifically, in the preamble to the 

proposed rule, we stated: 

“The statute directs the Agency to regulate EGUs under 

section 112 if the Agency finds such regulation is 

appropriate and necessary. Once the appropriate and 

necessary finding is made, EGUs are subject to section 

112 in the same manner as other sources of HAP 

emissions. Section 112(n)(1)(A) provision provides, in 

part, that: ‘[t]he Administrator shall perform a study

of the hazards to public health reasonably anticipated 

to occur as a result of emissions by electric utility 

steam generating units of pollutants listed under 

subsection (b) of this section after imposition of the 
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requirements of this chapter...The Administrator shall 

regulate electric utility steam generating units under 

this section, if the Administrator finds such 

regulation is appropriate and necessary after 

considering the results of the study required by this 

subparagraph.’” Emphasis added.

In the first sentence, Congress described the 

study and directed the Agency to evaluate the hazards 

to public health posed by HAP emissions listed under 

subsection (b) (i.e., CAA section 112(b)). The last 

sentence requires the Agency to regulate under this 

section (i.e., CAA section 112) if the Agency finds 

such regulation is appropriate and necessary after 

considering the results of the study required by this 

subparagraph (i.e., CAA section 112(n)(1)(A)). The use 

of the terms “section”, “subsection”, and

“subparagraph” demonstrates that Congress was 

consciously distinguishing the various provisions of 

CAA section 112 in directing the conduct of the study 

and the manner in which the Agency must regulate EGUs 

if the Agency finds it appropriate and necessary to do 

so. Congress directed the Agency to regulate utilities 

“under this section,” and accordingly EGUs should be 
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regulated in the same manner as other categories for 

which the statute requires regulation. 

See 76 FR 24993.

We maintain that our interpretation of the statute gives 

meaning to all the words, and the commenter’s interpretation 

does not give any particular meaning to the requirement to 

“regulate under this section [112]”. The commenter is correct 

that Congress could have in CAA section 112(n)(1)(A) directed 

EPA to regulate HAP from EGUs under CAA section 112(d) after 

making the appropriate and necessary finding, but the commenter 

presumes too much when it stated that Congress would have 

directed the Agency to regulate HAP emissions from EGUs in such 

a manner if that is what Congress wanted, simply by including 

the phrase “regulate under this paragraph” or “regulate under 

this subparagraph” instead of directing the Agency to “regulate 

under this section. It did not do so.

As we explained in the section II.A. of the proposed rule, 

CAA section 112 establishes a mechanism to list and regulate 

stationary sources of HAP emissions. 76 FR 24980-81. Regulation 

under CAA section 112 generally requires listing under CAA 

section 112(c), regulation under CAA section 112(d), and, for 

sources subjected to MACT standards, residual risk regulations 

under CAA section 112(f) (as necessary to protect human health 
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and the environment with an ample margin of safety). A 

determination that EGUs should be listed once the prerequisite 

appropriate and necessary finding is made is wholly consistent 

with the language of section 112(n)(1)(A), and listed sources 

must be regulated under CAA section 112(d). See CAA section 

112(c)(2); see also New Jersey, 517 F.3d at 583 (112(n)(1)(A) 

“governs how the Administrator decides whether to list EGUs”). 

As noted above, Congress used the terms section, 

subsection, and subparagraph in section 112(n)(1)(A). The use of 

these three terms demonstrates that Congress was consciously 

distinguishing between the various provisions of section 112. 

Congress directed the Agency to regulate utilities “under this 

section,” and accordingly EGUs should be regulated in the same 

manner as other categories for which the statute requires 

regulation. 

Furthermore, the flaws in the commenter’s interpretation 

are highlighted by other CAA section 112 provisions wherein 

Congress provided specific direction as to the manner of 

regulation. For example, CAA section 112(m)(6) requires the 

Administrator to determine “whether the other provisions of this 

section [112] are adequate” and also indicates that “[a]ny 

requirements promulgated pursuant to this paragraph...shall only 
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apply to the coastal waters of the States which are subject to 

[section 328 of the CAA].” (emphasis added). 

In addition, CAA section 112(n)(3) provides that when the 

Agency is “promulgating any standard under this section [112] 

applicable to publicly owned treatment works, the Administrator 

may provide for control measures that include pretreatment of 

discharges causing emissions of hazardous air pollutants and 

process or product substitutions or limitations that may be 

effective in reducing such emissions.” Finally, CAA section 

112(n)(5) directs the Agency to assess hydrogen sulfide 

emissions from oil and gas extraction and “develop and implement 

a control strategy for emissions of hydrogen sulfide to protect 

human health and the environment...using authorities under [the 

CAA] including [section 111] of this title and this section 

[112].” (emphasis added). We believe these provisions provide 

ample evidence that Congress knew how to alter or caveat 

regulation under CAA section 112 when that was its intent. For 

these reasons, we believe commenter’s argument is without merit.

Comment: Two commenters stated that CAA section 112(n)(1)(A) 

does not specify that regulation of EGUs must proceed under CAA 

section 112(d). According to the commenter, an argument could be 

made, therefore, that the CAA accords EPA with the discretion to 

regulate EGUs using strategies other than emission standards in 
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CAA section 112(d). The commenters also state that section 

112(n)(1)(A) of the CAA requires that EPA “develop and describe”

alternative control strategies for emissions which may warrant 

regulation under CAA section 112. According to the commenters if 

Congress meant for EPA to have one sole regulatory option, i.e., 

regulation of EGUs only under CAA section 112(d), then the 

development of alternative control strategies would be rendered 

meaningless because under CAA section 112(d)(3), the EPA is 

required to determine the level of control that is achieved by 

the best performing existing units for which it has data and 

then to impose that level of control on all existing units. The 

commenter further states that the development of “alternative 

control strategies” has no role to play in this process. One 

commenter does note that the consideration of “alternative”

controls becomes relevant, if at all, only in those 

circumstances where EPA might seek to establish a “Beyond-theFloor” MACT standard pursuant to CAA section 112(d)(2).

Response: The commenters are correct that CAA section 

112(n)(1)(A) directed the Agency to develop and describe in the 

Utility Study report to Congress alternative control strategies 

for HAP emissions from EGUs that may warrant regulation in the 

Utility Study, but the commenters’ interpretation of and 
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conclusion based on that language are both factually and legally 

inaccurate. 

The commenters appear to interpret the word “alternative 

control strategies” to mean something other than the traditional 

control technologies and control measures that are used to 

control HAP emissions from EGUs. We do not believe that is a 

reasonable interpretation of the statute, and the Agency did not 

interpret the statute in that manner when it conducted the 

Utility Study. In Chapter 13 of the Utility Study, the EPA 

considered a range of control measures that would reduce the 

different types of HAP emitted from EGUs. 

http://www.epa.gov/ttn/atw/combust/utiltox/eurtc1.pdf. The EPA 

considered pre-combustion controls such as coal washing, fuel 

switching, and gasification; combustion controls such as boiler 

design; post-combustion controls such as fabric filters, 

scrubbers, and carbon absorption; and alternative controls 

strategies such as demand-side management, energy conservation, 

and use of alternative fuels (e.g., biomass) or renewable 

energy. The options discussed in the Utility Study for 

controlling HAP emissions from EGUs are almost universally 

available to comply with a CAA section 112(d) standard. 

Given the manner in which the Agency conducted the Utility 

Study, the EPA interpreted the statutory direction as a 
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requirement to set forth the potential alternative control 

options available to EGUs to comply with CAA section 112 

standards in the event the Agency determined regulation under 

section 112 was appropriate and necessary. The EPA’s development 

and discussion in the Utility Study of alternative control 

strategies for complying with the standards would help prepare 

EGUs to comply with the standards if promulgated. Thus, the EPA 

interpreted the direction to address control strategies in the 

Utility Study as a request to identify the controls available to

EGUs for addressing HAP emissions, and such information would, 

of course, be relevant if EPA determined that such emissions 

warranted regulation under section 112.

Furthermore, the EPA establishes CAA section 112(d) 

standards for stationary sources and it is the responsibility of 

the sources to comply with the standards using any mechanism 

available, including pre-combustion and post-combustion 

measures. Also, the establishment of a MACT standard under CAA 

section 112(d)(2) and (3) is a two-step process. In the first 

step, the Agency establishes a floor based on the performance of 

the best controlled unit or units. See CAA section 112(d)(3). In 

the second step, the Agency must consider additional measures 

that may reduce HAP emissions and adopt such measures if 

reasonable after considering costs and non-air quality health 
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and environmental effects. See CAA section 112(d)(2). Under the 

second step, the Agency can consider any measure that reduces 

HAP emissions even if no source in the category is employing the 

option under consideration. So, even under the commenter’s 

flawed interpretation of “alternative control strategies”, the 

direction in CAA section 112(n)(1)(A) is not a “pointless 

exercise” for the development of CAA section 112(d) standards as 

the Agency considers relevant technologies and HAP emission 

reduction approaches in evaluating whether to set a more 

stringent beyond the floor standard.

Comment: One commenter points to CAA section 307(d)(1)(C) and 

notes that CAA section 112(n) is listed among the provision for 

which the rulemaking requirements of CAA 307(d) apply. Commenter 

maintains that this inclusion creates an expectation under the 

statute that EPA may establish regulatory standards under CAA 

112(n). The commenter points to CAA sections 112 (n)(1), (n)(3), 

and (n)(5) and states that those provisions specifically discuss 

regulation under CAA section 112 and that EPA must explain why 

CAA 307(d)(1)(C) states “any regulation under” CAA 112(n) to 

defend regulation of utilities under section 112(d). The 

commenter then implies that EPA erred by not even mentioning 

this provision at proposal. 
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The commenter also takes issue with EPA’s statement in the 

proposed rule that “use of the terms section, subsection, and 

subparagraph” “demonstrates that Congress was consciously 

distinguishing the various provisions of section 112 in 

directing the conduct of the study and the manner in which the 

Agency must regulate EGUs,” if EPA determines that it is 

appropriate and necessary to regulate EGUs. See 76 Fed. Reg. at 

24,993/2.

One commenter does not agree with the EPA’s finding that 

the word “subsection” in the first sentence of CAA section 

112(n)(1)(A) demonstrates that Congress was consciously 

distinguishing between the various provisions of CAA section 112 

in directing the conduct of the study and the manner in which 

the Agency must regulate EGUs,” were the EPA to “find[] it 

appropriate and necessary to do so.” See 76 FR 24993/2. 

According to the commenter, the only evident reason that the 

word “subsection” is used in the first sentence of CAA section 

112(n)(1)(A) is because the reference is made to the

“pollutants” which the Utility Study is to address – i.e., the 

“pollutants” that are emitted by EGUs and which are “listed 

under subsection (b)” of CAA section 112. Similarly, the word 

“subparagraph” is used in the last sentence of CAA section 

112(n)(1)(A) to identify “the study” which the EPA is directed 
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to undertake by subparagraph (A) of CAA section 112(n)(1) –

i.e., the Utility Study. That the last sentence of subparagraph 

(n)(1)(A) also states that EPA “shall regulate electric utility 

steam generating units under this section” does not even imply –

much less expressly communicate – that regulation “under this 

section” must mean “regulation under section 112(d).” The 

commenter stated that Congress was “consciously distinguishing”

between the “various provisions of section 112” for the sake of 

clarity in the drafting of CAA section 112(n).

The commenter also asserts that the EPA mistakenly relies 

on section 112(c)(6) when the EPA states that “‘where Congress 

wished to exempt EGUs from specific requirements of section 112, 

it said so explicitly. Congress did not exempt EGUs from the 

other requirements of section 112,’” and thus the Agency is 

“‘required to establish emission standards for EGUs consistent 

with the requirements set forth in section 112(d)’” (citing 76 

Fed. Reg. at 24,993 (internal quotation omitted)). 

According to the commenter, nothing in section 112(c)(6) 

indicates how (or even whether) EGU HAP emissions should be 

regulated under section 112; paragraph (c)(6) serves only to 

reiterate that the regulation of such emissions is to occur (if 

at all) as is provided by section 112(n)(1). The commenter also 

asserts that the EPA mistakenly relies on New Jersey. According 
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to the commenter, the D.C. Circuit in that case did not indicate 

that the language of section 112(c)(6) should, or could, be 

construed to mean that EGUs must be regulated under a MACT 

standard adopted pursuant to section 112(d).

Response: The commenter makes a number of arguments that appear 

to take issue with the EPA’s determination that EGUs should be 

regulated under CAA section 112(d) if the Agency determines that 

regulation of HAP emissions from such units is appropriate and 

necessary. The commenter implies that the EPA erred because 

alternative mechanisms for regulation of EGUs under CAA section 

112 might exist. We do not agree.

The commenter’s argument that the EPA erred because we did 

not explain why section CAA section 307(d)(1)(C) contemplates 

regulations under CAA section 112(n) is without merit. It is 

correct that the Agency believes EGUs should be regulated in the 

same manner as other sources if the appropriate and necessary 

finding is made because of the structure of CAA section 112. 

Nothing in CAA section 112(n)(1) requires or implies that the 

Agency should or must establish standards for EGUs under that 

provision. Furthermore, unlike CAA sections 112(n)(3) and 

112(n)(5) that commenter cites, CAA section 112(n)(1)(A) does 

not provide any guidance concerning the manner in which EPA is 

authorized or required to regulate sources under CAA section 
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112. See CAA section 112(n)(3) (specifically authorizing 

identified control measures and other requirements for 

consideration in issuing standards under CAA section 112); see

also CAA section 112(n)(5) (directing the Agency to develop and 

implement a control strategy for emissions of hydrogen sulfide 

using any authority available under the CAA, including sections 

112 and 111, if regulation is appropriate). For these reasons, 

we disagree that any error occurred because we did not 

specifically discuss in this proposed rule whether we could or 

should regulate EGUs under CAA section 112(n)(1) instead of CAA 

section 112(d).64 The Agency validly listed EGUs in 2000 and 

listed sources must be regulated pursuant to CAA section 112(d). 

Even if we agreed that regulation under CAA section 

112(n)(1) was a viable option for EGUs, we would still have 

listed and regulated EGUs like other sources because CAA section 

112(d) provides a statutory framework for regulating HAP 

emissions from sources and CAA section 112(n)(1) does not. We 

 

64 We note that in our January 2004 proposed rule, we solicited 

comment on whether section 112(n)(1)(A) provided independent 

authority to regulate EGUs. We received several comments on this 

issue, and we rejected the concept after reviewing the comments 

and further considering the language of section 112(n)(1)(A) and 

the structure of section 112. As such, we proposed and are 

finalizing that once the Agency determines that it is 

appropriate and necessary to regulate EGUs under section 112, 

those sources are listed pursuant to subsection 112(c), as we 

did in December 2000, and the Agency must set standards for 

those sources pursuant to section 112(d). See section 112(c) and 

(d)(1) (requiring establishment of 112(d) standards for listed 

source categories). 
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believe that even if CAA section 112(n)(1) were available to 

regulate EGUs, there would be sufficient uncertainty about the 

legal vulnerability of such an approach to caution against 

employing it. This legal uncertainty would be particularly 

troubling in light of the fact that we have identified hazards 

to public health and the environment from HAP emissions from 

EGUs that warrant regulation, and these regulations are long 

overdue. 

The commenter also takes issue with our statement in the 

preamble to the proposed rule that the use of the words 

“section”, “subsection”, and “subparagraph” in CAA section 

112(n)(1)(A) “demonstrates that Congress was consciously 

distinguishing the various provisions of section 112 in 

directing the conduct of the study and the manner in which the 

Agency must regulate EGUs.” See 76 FR 24993. The commenter 

appears to make much of our use of the word “must” in that 

sentence and also states that our interpretation of the 

significance of the use of the three terms in CAA section 

112(n)(1)(A) is flawed because Congress only used the three 

terms for purposes of clarity. The commenter is incorrect on 

both points. With respect to the commenter’s concern regarding 

the use of the word “must” in the sentence quoted above, we note 

that in the next sentence we stated that “Congress directed the 
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Agency to regulate utilities ‘under this section,’ and 

accordingly EGUs should be regulated in the same manner as other 

categories for which the statute requires regulation.” Id. 

(emphasis added). We were not foreclosing the possibility of any 

alternative interpretation and our use of the term “must” should 

not detract from the point we were trying to make. Specifically, 

we believe that Congress would have directed us to regulate EGUs 

under CAA section 112(n)(1)(A) if that was its intent and, 

absent that mandate, the better reading of the statute is the 

one provided in the preamble to the proposed rule, which is that 

EGUs should be listed pursuant to CAA section 112(c) and subject 

to CAA section 112(d) emission standards.

The commenter also stated that the EPA relied on CAA 

section 112(c)(6) to support a conclusion that EGUs must be 

regulated under CAA section 112(d). The commenter takes the 

EPA’s statements out of context. The statement in whole read:

“Furthermore, the D.C. Circuit Court has already held 

that section 112(n)(1) “governs how the Administrator 

decides whether to list EGUs” and that once listed, 

EGUs are subject to the requirements of CAA section 

112. New Jersey, 517 F.3d at 583. Indeed, the D.C. 

Circuit Court expressly noted that “where Congress 

wished to exempt EGUs from specific requirements of 
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section 112, it said so explicitly,” noting that 

“section 112(c)(6) expressly exempts EGUs from the 

strict deadlines imposed on other sources of certain 

pollutants.” Id. Congress did not exempt EGUs from the 

other requirements of CAA section 112, and once 

listed, EPA is required to establish emission 

standards for EGUs consistent with the requirements 

set forth in CAA section 112(d), as described below.”

See 76 FR 24993.

As can be seen from this passage, the Court cited section 

112(c)(6) as an example of Congress’ intent regarding regulating 

EGUs under CAA section 112. The commenter cited the last clause 

of the last sentence of the paragraph quoted above without 

including the prefatory clause “once listed,” and, without that 

clause, the statement is not fairly characterized. The point the 

EPA was making in that paragraph is that EGUs are a listed 

source category and listed sources must be regulated under CAA 

section 112(d) unless the EPA delists the source category.

Comment: One commenter stated that EPA overstates the 

significance of the D.C. Circuit’s holding in New Jersey by 

suggesting that the decision mandates EGU regulation under CAA 

section 112(d) because EGUs “remain listed” under CAA section 

112(c), See New Jersey, 517 F.3d at 582. According to the 
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commenter, the court declined to address the lawfulness of EPA’s 

having “listed” EGUs under CAA section 112(c), leaving that 

matter to be decided if and when EPA adopted standards for EGUs 

under CAA section 112. Nowhere in the decision did the D.C. 

Circuit indicate that EPA must regulate EGUs under CAA section 

112(d).

According to the commenter, the EPA must consider both 

whether the regulation of EGUs is “appropriate and necessary”

under section 112(n)(1) and address anew whether the Agency is 

authorized by section 112 to list EGUs under section 112(c) at 

all. The commenter asserts that on the face of the proposal, the 

EPA has not revisited the question whether the “listing” of EGUs 

under section 112(c) is consistent with congressional intent.

Response: The commenter’s arguments are circular and it is 

difficult to fully determine exactly what its issue is with 

EPA’s listing; however, it appears that the commenter believes 

that EPA incorrectly relied on the New Jersey decision to 

justify the listing of EGUs. The commenter also appears to argue 

that the Agency has never explained why it has the authority to 

list EGUs at all. We disagree.

As stated in the preamble to the proposed rule, CAA section 

112(n)(1)(A) requires EPA to conduct a study of HAP emissions 

from EGUs and regulate EGUs under CAA section 112 if we 
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determine that regulation is appropriate and necessary, after 

considering the results of the study. 76 FR 24981, 24986, and 

24998. The only condition precedent to regulating EGUs under CAA 

section 112 is a finding that such regulation is appropriate and 

necessary (after conducting and considering the Utility Study), 

and once that finding is made the Agency has the authority to 

list EGUs under CAA section 112(c) as the first step in the 

process of establishing regulations under section 112. The D.C. 

Circuit agrees with that interpretation of the statute as 

evidenced by its statement in New Jersey that “section 

112(n)(1)(A) governs how the Administrator decides whether to 

list EGUs for regulation under section 112,” 517 F.3d at 582, 

and the Court’s statement directly contradicts the commenter’s 

position. 

The EPA did not rely on the New Jersey decision to justify 

the appropriate and necessary finding as the commenter suggests. 

We based the finding in 2000 on the extensive information 

available to the Agency at the time, and we confirmed the 

finding in the preamble to the proposed rule based on new 

information. The commenter had ample opportunity to comment on 

the appropriate and necessary finding, and it may challenge the 

basis of the listing (i.e. the appropriate and necessary 

finding) when EPA issues the final standards.
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Comment: One commenter believes that the D.C. Circuit will 

condemn the final rule as a result of EPA’s “misapprehension”

that upon making an “appropriate and necessary” finding, the 

Agency is compelled by the CAA to adopt a regulatory standard 

for EGUs under CAA section 112(d). According to the commenter, a 

regulation will be invalid if the regulation “‘was not based on 

the [agency’s] own judgment’” but “‘rather on the unjustified 

assumption that it was Congress’ judgment that such [a 

regulation] is desirable’ or required.” See Transitional 

Hospitals Corp. v. Shalala, 222 F.3d 1019, 1029 (D.C. Cir. 

2000), quoting Prill v. NLRB, 755 F.2d 941, 948 (D.C. Cir. 

1985). The commenter further notes that the D.C. Circuit has 

held that, where an agency wrongly construes a judicial decision 

as compelling a particular statutory interpretation, and thereby 

unduly limits the scope of its own discretion, the agency’s 

action cannot be sustained. See, e.g., Phillips Petroleum Co. v. 

FERC, 792 F.2d 1165, 1171 (D.C. Cir. 1986). The commenter 

believes the rule is bound to be rejected and that the EPA 

should “reconsider the legal interpretations on which it 

purports to base its rule.”

Response: We do not agree that we have improperly interpreted 

the statute as limiting our discretion in the manner suggested 

by the commenter. The commenter makes only one specific 
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allegation in this comment and that concerns the Agency’s 

conclusion that it must establish CAA section 112(d) standards 

for EGUs in light of the New Jersey decision. The commenter does 

not explain why that conclusion is incorrect. As we state above 

and in the preamble to the proposed rule, because EGUs are a CAA 

section 112(c) listed source category, the Agency must establish 

CAA section 112(d) standards or delist EGUs pursuant to CAA 

section 112(c)(9). See New Jersey, 517 F.3d at 582-83 (holding 

that EGUs remain listed under section 112(c)); see also CAA 

section 112(c)(2) (requiring the Agency to “establish emission 

standards under subsection [112] (d)” for listed source 

categories and subcategories); 76 FR 24998-99. We concluded in 

the preamble to the proposed rule that we could not delist EGUs 

because our appropriate and necessary analysis showed that EGUs 

did not satisfy the CAA section 112(c)(9)(B)(i) delisting 

criteria. Id. We did not address in the preamble to the proposed 

rule whether EGUs satisfied the CAA section 112(c)(9)(B)(ii) 

criteria because EGUs failed the first prong of the delisting 

provisions. Id. We reach the same conclusion in the final rule 

and also address the delisting petition submitted by this 

commenter. Because we cannot delist EGUs, we must regulate them 

under CAA section 112(d). The commenter has provided no 
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legitimate argument to rebut this conclusion. See also previous 

responses regarding regulation under section 112(n)(1)(A).

Comment: One commenter alleges that EPA impermissibly relied on 

CAA section 112(c)(9) to interpret “hazards to public health”, 

and argues that the “residual risk” provisions in CAA section

112(f)(2) are more appropriate for the establishment of 

standards for EGUs. The commenter stated that by using CAA 

section 112(c)(9)(B)(i) in defining “hazards to public health”, 

the Agency has seized on the one interpretation of the phrase 

that is surely contrary to congressional intent and, thus, falls 

outside the permissible range of its interpretative discretion. 

The commenter maintains that the “delisting” criteria of CAA 

section 112(c)(9) are simply irrelevant to the decision whether 

EGU HAP emissions will present any “hazards to public health”

sufficient to warrant regulation of those emissions under CAA 

section 112.

The commenter also argues that Congress intended that EGUs 

be treated differently from all other “major sources” to which 

the “delisting” provisions of CAA section 112(c)(9), and the 

standard-setting provisions of CAA section 112(d) necessarily 

and automatically apply. Therefore, according to the commenter, 

the EPA’s proposal to utilize the criteria of CAA section 

112(c)(9) to inform its findings under CAA section 112(n)(1)(A) 
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treats EGUs exactly the same as all other major source 

categories, is contrary to congressional intent, and thus 

unlawful. The commenter goes on to state that in exercising its 

discretion to define “hazards to public health” as the phrase is 

used in CAA section 112(n)(1)(A), the EPA would be better served 

to consider the “residual health risk” provisions of CAA section 

112(f)(2). Those provisions provide a better analogy to the 

establishment of standards for EGUs under CAA section 112 than 

do the “de-listing” criteria of CAA section 112(c)(9).

The commenter believes the category-specific criteria of 

paragraph (c)(9) are a poor fit for an evaluation of “hazards to 

public health” that should reasonably include such factors as 

the affected population, the characteristics of exposure, the 

nature of the health effects, and the uncertainties associated 

with the data. The commenter states that, while CAA section 

112(n)(1)(A) does not expressly include any requirement that EGU 

emissions be regulated with an “ample margin of safety,” that 

standard is more appropriate than the “one-in-a-million” cancer 

risk standard of CAA section 112(c)(9)(B)(i) that EPA proposes 

to employ. 

Response: The commenter acknowledges that EPA has broad 

discretion to interpret the phrase “hazard to public health” but 

argues that the one thing we cannot do is use the CAA section 
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112(c)(9)(B) delisting provisions as a benchmark in making that 

interpretation. The commenter asserts that the use of the 

delisting standard is clearly contrary to Congressional intent 

but it does not provide any substantive rebuttal to our 

conclusion that the CAA section 112(c)(9) standards reflects the 

level of hazard which Congress concluded warranted continued 

regulation. Instead, the commenter reverted to its argument that 

the statute treated EGUs differently. The EPA views the 

disparate treatment of EGUs in a different light than commenter. 

While it is true that Congress established a different statutory 

provision governing whether to add EGUs as a regulated source 

category under section 112, we do not interpret CAA section 

112(n)(1)(A) as providing Congressional license to ignore risks 

that Congress determined warranted regulation for all other 

source categories. Because CAA section 112(c)(9) defines that 

level of risk, it is reasonable to consider it when evaluating 

whether EGU HAP emissions pose hazards to public health. 

The commenter also suggests that the “ample margin of 

safety standard” of CAA section 112(f)(2) is a better fit than 

the one-in-a-million standard set forth in CAA section 

112(c)(9)(B)(1) for evaluating hazards to public health. The 

commenter asserts that an evaluation of “hazards to public 

health” should include such factors as the affected population, 
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the characteristics of exposure, the nature of the health 

effects, and the uncertainties associated with the data. 

However, the EPA did not rely solely on the delisting provisions 

for evaluating hazards to public health as commenter suggests. 

In fact, the EPA considered all of the factors the commenter 

suggests in making our finding.65 Thus, we decline to adjust our 

approach to evaluating hazards to public health and the 

environment based on the comments.

h. 2000 Finding (and 2005 Delisting)

Comment: Several commenters generally support EPA’s 2000 finding

that regulating HAP emissions from EGUs under CAA section 112 is 

“appropriate and necessary.” According to the commenters, the 

2000 finding was proper under the CAA and within EPA’s 

discretion, well-supported based on sound science available to 

the Agency at the time on the harm from HAP emitted by EGUs, and 

no additional information makes the finding invalid. Several 

commenters cited the conclusions of the Utility Study66 and 

Mercury Study67, which they assert supported the finding and 

satisfied the only prerequisite for the finding. One commenter 

specifically asserted that the 2000 finding was well-supported 

by the Utility Study’s conclusions that (1) there was a link 

 

65 76 FR 24992.

66 U.S. EPA 1998. Study of Hazardous Air Pollutant Emissions from 

Electric Utility Steam Generating Units —Final Report to 

Congress. EPA–453/R–98–004a. February.

67 U.S. EPA, 1997.
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between anthropogenic Hg emissions and MeHg found in freshwater 

fish, (2) Hg emissions from coal-fired utilities were expected 

to worsen by 2010, and (3) MeHg in fish presents a threat to 

public health from fish consumption. One commenter noted that 

the CAA does not require a conclusive link between HAP emissions 

and harm. One commenter stated that the CAA grants the 

Administrator discretion in her finding, and that discretionary 

decision should not be overly scrutinized, citing court 

opinion.68 In support of the finding, one commenter stated that 

it would not make sense for Congress to limit HAP emissions from 

small businesses such as dry cleaners but to exempt U.S. EGUs, 

which are the largest sources of many HAP emissions. One 

commenter agreed that finding was further supported because 

numerous control options were available to reduce HAP emissions. 

One commenter agreed with the 2000 finding that the Agency 

lacked sufficient evidence to conclude that non-Hg HAP from EGUs 

posed no hazard.

The commenters who generally supported the 2000 finding 

also commented on specific aspects of the finding. Several 

commenters asserted that while the evidence on Hg alone supports 

 

68 “Where a statute is precautionary in nature, the evidence 

difficult to come by, uncertain, or conflicting because it is on 

the frontiers of scientific knowledge, the regulations designed 

to protect the public health, and the decision that of an expert 

administrator, [courts] will not demand rigorous step-by-step 

proof of cause and effect.” Ethyl Corp. v. EPA, 541 F.2d 1, 28 

(Ct. App. D.C. Circ. 1978)
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the finding, the potential harm from non-Hg HAP further 

supported the 2000 finding. Several commenters noted that new 

science continues to support the 2000 finding. Several 

commenters also stated that the “appropriate” finding was 

further supported because numerous control options were 

available at the time of the finding that would reduce HAP 

emissions. One commenter concurred with EPA that regulating 

natural gas-fired EGUs was not appropriate and necessary because 

the impacts due to HAP emissions from such units are negligible 

based on the results of the Utility Study. 

Several commenters addressed the 2005 reversal of the 2000 

finding. Several commenters specifically supported the vacatur 

of the 2005 action. Other commenters asserted that the 2005 

action was proper, and that EPA reverted back to the 2000 

finding in the proposed rule without adequate explanation or 

support. Several commenters cited the 2005 action as 

invalidating the 2000 finding, specifically noting that EPA 

concluded that “no hazards to public health” remained after 

accounting for emission reductions under CAIR. These commenters 

assert that EPA’s current position is illegal because EPA took 

the exact opposite position on the interpretation of the term 

“necessary” in its 2005 reversal, and, thus, deserves no 

judicial deference. One commenter stated that in 2005 EPA 
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recognized the potential for excessive regulation created by CAA 

section 112 and determined that the 2000 finding lacked 

foundation. 

Several commenters generally disagreed with the 2000 

finding, with two commenters stating that EPA did not have a 

rational justification for it and another claiming that it was 

fraught with misinformation and overestimating assumptions. One 

commenter claimed that EPA did not explain the terms 

“appropriate” and “necessary” in the 2000 finding and that the 

emission control analysis was inadequate. Two commenters stated 

that the 2000 finding was based on data that was more than 10 

years old, which causes serious concern regarding the validity 

of the findings because technology, the regulatory environment, 

and the economic climate have evolved. Furthermore, because the 

Utility Report underestimated emissions controls that EGUs would 

install by 2010 and additional controls that would be later 

required by the CSAPR, the basis for EPA’s 2000 finding has 

changed. Several commenters stated that a “plausible link”

between anthropogenic Hg and MeHg in fish is not an adequate 

reason for the 2000 finding. Several commenters claim that EPA 

only identified health concerns for Hg (and potentially Ni) but 

not other HAP from coal-fired EGUs in the 2000 finding, and, 

thus, cannot regulate HAP other than Hg because the 2000 finding 
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authorizes only the regulation of Hg. One commenter questioned 

the Hg emissions underlying the 2000 finding, specifically the 

fraction of total deposition attributable to U.S. EGUS and the 

fact that EPA projected an increase in U.S. EGU emissions from 

1990 to 2010 though emissions actually declined. 

Several commenters raised procedural issues related to the 

2000 finding. Several commenters stated that the 2000 finding 

failed to provide public notice and comment. According to the 

commenters, the CAA requires that any decision made under CAA 

section 112(n) must go through public notice and comment. The 

commenters further stated that the failure to provide public 

notice and comment means that this MACT is outside EPA’s 

statutory authority. One commenter stated that because the 2000 

finding was never “fully ventilated” in front of the D.C. 

Circuit, the EPA’s authority to regulate EGUs under CAA section 

112(d) is directly at issue. The commenters claim that specific 

issues did not undergo public notice and comment, including 

least-cost regulatory options, the impact of regulation on 

electricity reliability, and EPA’s interpretation of the 

requirements under CAA section 112(n)(1)(A). One commenter 

claims that EPA attempted to provide after-the-fact support for 

its 2000 finding with new legal analysis and new factual 

information, contrary to New Jersey v. EPA that held that EPA 
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may not revisit its 2000 finding except through delisting under 

CAA section 112(c)(9). One commenter stated that EPA’s 2000 

finding should be reviewed when EPA issues the actual NESHAP.69

One commenter stated that the 2000 finding ignored EO 12866.

Response: EPA agrees with the commenters that the 2000 finding 

was reasonable and disagrees with the commenters asserting that 

the 2000 finding was unreasonable or failed to follow proper 

procedural requirements. 

The EPA agrees that reviewing courts defer to the reasoned 

scientific and technical decisions of an Agency charged with 

implementing complex statutory provisions such as those at issue 

in this case. As EPA stated in the preamble to the proposed 

rule, the EPA maintains that the 2000 finding was reasonable and 

based on well-supported evidence available at the time, 

including the Utility Study, the Mercury Study,70 and the NAS 

study,71 which all showed the hazards to public health and the 

environment from HAP emitted from EGUs. New technical analyses 

conducted by EPA confirm that it remains appropriate and 

necessary to regulate HAP emissions from EGUs. Furthermore, the 

EPA agrees with the commenters on several points raised, 

specifically that EGUs were and remain the largest anthropogenic 

 

69 See UARG v. EPA, 2001 WL 936363, No. 01-1074 (D.C. Cir. July 

26, 2001).

70 U.S. EPA, 1997.

71 NAS, 2000.
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source of several HAP in the U.S., that risk assessments 

supporting the 2000 finding indicated potential concern for 

several non-Hg HAP, and that several available control options 

would effectively reduce HAP emissions from U.S. EGUs.

The EPA agrees with the commenters that Congress did not 

exempt EGUs from section 112(d) HAP emission limits while 

simultaneously limiting emissions at other sources with less HAP 

emissions. Congress simply provided EPA with a separate path for 

listing EGUs by requiring that the Agency evaluate HAP emissions 

from EGUs and determine whether regulation under CAA section 112 

was appropriate and necessary. Since 1990, the EPA has 

promulgated regulations requiring the use of available control 

technology and other practices to reduce HAP emissions for more 

than 170 source categories. U.S. EGUs are the most significant 

source of HAP in the country that remains unaddressed by 

Congress’s air toxics program. The EPA listed EGUs in 2000 

because the considerable amount of available data supported the 

conclusion that regulation of EGUs under CAA section 112 was 

appropriate and necessary. That finding was valid at the time, 

and EPA reasonably added EGUs to the CAA section 112(c) list of 

sources that must be regulated under CAA section 112.

The EPA acknowledges that we did not expressly define the 

terms appropriate and necessary in the 2000 finding, but the 
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finding is instructive in that it shows that EPA considered 

whether HAP emissions from EGUs posed a hazard to public health 

and the environment and whether there were control strategies 

available to reduce HAP emissions from EGUs when determining 

whether it was appropriate to regulated EGUs.72 When concluding 

it was necessary, the Agency stated that imposition of the 

requirements of the Act would not address the identified hazards 

to public health or environment from HAP emissions and that 

section 112 was the proper authority to address HAP emissions.73

The EPA explained in the preamble to the proposed rule its 

conclusion that the 2000 finding was fully supported by the 

information available at the time,74 and EPA stands by the 

conclusions in that notice. Furthermore, the EPA provided an 

interpretation of the terms appropriate and necessary that is 

wholly consistent with the 2000 finding. The EPA does not agree 

with the commenters that a quantification of emissions 

reductions or a specific identification of the available 

controls was necessary to support the 2000 finding and listing. 

The EPA considered the Utility Study when making the finding, 

and that study clearly articulated the various alternative 

control strategies that EGUs could employ to control HAP 

 

72 65 FR 79830.

73 Id.

74 65 FR 24994-24996.
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emissions.75 As to emission reductions, the EPA cannot estimate 

the level of HAP emission reductions until the Agency proposes a 

CAA section 112(d) standard after a source category is listed.

The EPA disagrees with commenters that suggest it was not 

“rational” to determine that it was appropriate to regulate HAP 

emissions from EGUs due to the cancer risks identified in the 

Utility Study or the potential concerns associated with other 

HAP emissions from EGUs. Nothing in CAA section 112(n)(1)(A) 

suggests that EPA must determine that every HAP emitted by EGUs 

poses a hazard to public health or the environment before EPA 

can find it appropriate to regulate EGUs under CAA section 112. 

In fact, the EPA maintains that it must find it appropriate and 

necessary to regulate EGUs under CAA section 112 if it 

determines that any one HAP emitted from EGUs poses a hazard to 

public health or the environment that will not be addressed

through imposition of the requirements of the Act. The EPA 

disputes the commenters’ conclusion that the 2000 finding was 

limited to Hg and Ni emissions, but, even if it were, the EPA 

reasonably concluded that EGUs should be listed pursuant to CAA 

section 112(c) based on the Hg and Ni finding. As stated in the 

2000 finding, cancer risks from some non-Hg metal HAP (including 

As, Cr, Ni, and Cd) were not low enough to be to eliminate as 

 

75 See Chapter 13 of the Utility Study (U.S. EPA, 1998). 
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potential concern.76 Source categories listed for regulation 

under CAA section 112(c) must be regulated under CAA section 

112(d), and the D.C. Circuit has stated that EPA has a “clear 

statutory obligation to set emission standards for each listed 

HAP”. See Sierra Club v. EPA, 479 F.3d 875, 883 (D.C. Cir. 

2007), quoting National Lime Association v. EPA, 233 F.3d 625, 

634 (D.C. Cir. 2000). Therefore, even if EPA concluded that CAA 

section 112(n)(1) authorized a different approach for regulating 

HAP emissions from EGUs, the chosen course which is supported by 

the CAA (i.e., listing under CAA section 112(c)) requires the 

Agency to regulate under CAA section 112(d) consistent with the 

statute and case law interpreting that provision. 

The EPA disagrees that there is any concern regarding the 

validity of the 2000 finding or that the emissions information 

provided in the 2000 finding makes the finding “questionable” as 

stated by some of the commenters. The EPA maintains that the 

2000 finding was sound and fully supported by the record 

available at the time, including the future year emissions 

projections. Therefore, the listing of EGUs is valid based on 

that finding alone. Even though Hg emissions have decreased 

since the 2000 finding instead of increasing as projected, the 

new technical analyses confirm that Hg emissions from EGUs 

continue to pose hazards to public health and the environment. 

 

76 76 FR 79827.
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The EPA also indicated potential concern for several non-Hg HAP

in the 2000 finding. It is well established that even small 

amounts of HAP can cause significant harm to human health and 

the environment. 

The EPA agrees with the commenters who assert that the 2005 

action was in error and disagrees with the commenters that the 

2005 action invalidated the 2000 finding. As fully described in 

the preamble to the proposal, the EPA erred in the 2005 action 

by concluding that the 2000 finding lacked foundation. The 2005 

action improperly conflated the “appropriate” and “necessary”

analyses by addressing the “after imposition of the requirements 

of the Act” in the appropriate finding as well as the necessary 

finding. The EPA also indicated that it was not reasonable to 

interpret the necessary prong of the finding as a requirement to 

scour the CAA for alternative authorities to regulate HAP 

emissions from stationary sources, including EGUs, when Congress 

provided section 112 for that purpose. The EPA asserts that the 

2000 finding was sound and fully supported by the record 

available at the time for all the reasons stated in this final 

rule and the proposed rule. The 2005 action interpreted the 

statute in a manner inconsistent with the 2000 finding and 

attempted to delist EGUs without complying with the mandates of 

CAA section 112(c)(9)(B). See New Jersey, 517 F.3d at 583 
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(vacating the 2005 “delisting” action). In the preamble to the 

proposed rule, the EPA set forth a revised interpretation of CAA 

section 112(n)(1) that is consistent with the statute and the 

2000 finding. The EPA also explained in the preamble to the 

proposed rule why the 2005 action was not technically or 

scientifically sound. The EPA specifically addressed the errors 

associated with the 2005 action in the preamble to the proposed 

rule, and commenters’ assertions do not cause us to revisit 

these issues. The commenter is also incorrect in suggesting that 

a change in interpretation is per se invalid and provided no 

support for that position. See National Cable & 

Telecommunications Ass’n, et. a., v. Brand X Internet Services, 

et al., 545 U.S. 967, 981 (discussing the deference provided to 

an Agency changing interpretations, the Court stated “change is 

not invalidating, since the whole point of Chevron deference is 

to leave the discretion provided by ambiguities of a statute 

with the implementing Agency.”) (Internal citations and 

quotations omitted).

The EPA disagrees with the commenters who raise concerns

about the validity of the 2000 finding because the data on which 

that finding was based were more than 10 years old. The EPA made 

the finding at that time based on the scientific and technical 

information available, and the finding is wholly supported by 
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that information. In addition, even though not required to do 

so, the EPA has since conducted new technical analyses utilizing 

the best information available in 2010 as several years have 

passed since the 2000 finding. These new analyses confirm that 

HAP emissions from EGUs continue to pose a hazard to public 

health and the environment, even after taking into account 

emission reductions that have occurred since 2000 from 

promulgated rules, settlements, and consent decrees. See 76 FR 

24991.

Contrary to the commenter’s assertion, the EPA did not 

violate CAA section 307(d) by not providing a notice and comment 

opportunity before making the December 2000 appropriate and 

necessary finding. One commenter challenged EPA’s 2000 finding 

and listing on the same grounds, and the D.C. Circuit dismissed 

the case because CAA section 112(e)(4) clearly states that 

listing decisions cannot be challenged until the Agency issues 

final emission standards for the listed source category. See 

UARG v. EPA, 2001 WL 936363, No. 01-1074 (D.C. Cir. July 26, 

2001). The EPA has provided the public an opportunity to comment 

on both the 2000 finding and the 2011 analyses that support the 

appropriate and necessary determination as part of the proposed 

rule, and anyone may challenge the listing in the D.C. Circuit 

in conjunction with a challenge to this final rule. The 
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commenters could have also commented on the CAA section 

112(n)(1) (e.g., the Utility Study and the Mercury Study)

studies in 2000 as they were included in the docket, but EPA is

not aware of any comments on those studies. In any case, these 

studies were peer reviewed and considered the best information 

available at that time. The EPA has fully complied with the 

rulemaking requirements of CAA section 307(d). 

The EPA also disagrees with the commenters’

characterization of the New Jersey case. The D.C. Circuit did 

not say, as one commenter suggested, that EPA is not able to 

consider additional information that is collected after the 2000 

finding; instead, the Court stated that EPA could not revise its 

appropriate and necessary finding and remove EGUs from the CAA 

section 112(c) list without complying with the delisting 

provisions of CAA section 112(c)(9). See New Jersey, 517 F.3d at 

582-83. The EPA also disagrees with the commenter’s assertion 

that EPA disregarded EO 12866 when making the 2000 finding. As 

stated in the Federal Register notice, the 2000 finding did not 

impose regulatory requirements or costs and was reviewed by the 

Office of Management and Budget (OMB) in accordance with the 

EO.77

2. New Technical Analyses

a. General comments on new technical analyses

 

77 65 FR 79831.
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Comment: Several commenters stated that the new analyses,

including the risk assessments and technology assessments,

confirm that it remains appropriate and necessary to regulate

U.S. EGU HAP under CAA section 112. These commenters stated that 

the new analyses provide even more support than the risk and 

technology information available at the time the 2000 finding 

was made, including information on further developed emissions 

control technology, proven and cost-effective control of acid 

gases using trona and dry sorbent injection, stabilized natural 

gas prices that makes fuel switching and switching dispatch to 

underutilized combined cycle plants more feasible, more 

information on ecosystem impacts from HAP, “hotspots” from the 

deposition of Hg around EGUs, the potential for re-emission of 

Hg, updated emissions data and future projections of HAP 

emissions, and modern air pollution modeling tools. One 

commenter states affordable control technology has been in use 

in this sector for 10 to 40 years, and studies on EGUattributable Hg hazard has undergone two in-depth EPA reviews, 

as well as a review by the NAS. Several commenters claimed that 

regulating U.S. EGUs is appropriate and necessary to protect 

public health based on information provided in the new technical 

analyses. These commenters acknowledged the substantial 

reductions in HAP from recent regulations and new studies that 
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confirm serious health risks from HAP exposure. One commenter 

stated that new studies show higher risks to fetuses than 

previously estimated, increasing the potential for 

neurodevelopmental effects in newborns. One commenter noted that 

EGUs are a major source of HAP, including HCl, HF, As, antimony, 

Cr, Ni, and selenium, all of which adversely affect human 

health. The commenter stated that because of these health 

effects, the EPA has ample evidence to support a determination 

that non-Hg HAP emissions present a risk to human health.

Other commenters disagreed that the new analyses confirm 

that it remains appropriate and necessary to regulate U.S. EGUs. 

One commenter claims that EPA tried to use the new technical 

analyses to provide retroactive justification for the 2000 

finding, which only found “plausible links” of health effects 

and “potential concerns” of health effects of certain metal 

emissions, dioxins and acid based aerosols. The commenter also 

asserted that none of these new analyses demonstrate that EGU 

regulation under section 112 is necessary and appropriate.

One commenter agreed that EPA may supplement its finding 

with new information, analyses and arguments to reaffirm the 

2000 finding up until EPA issues final emissions standards. The 

commenter noted that the CAA does not freeze the finding. 

However, another commenter argued that EPA does not have the 
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authority to rely on new technical analyses because the CAA 

requires EPA to make the finding on the basis of the Utility 

Study alone. According to that commenter, the EPA unreasonably 

stretched the language of CAA section 112 by considering new 

technical analyses.

Citing a report from Dr. Willie Soon that was submitted to 

the SAB, one commenter stated that the new technical analyses 

supporting the proposed rule do not conform to the Information 

Quality Act, which requires that information relied on by EPA be 

accurate, reliable, unbiased, and presented in a complete and 

unbiased manner. 

Response: The EPA agrees with the commenters that state that the 

new technical analyses (e.g., the risk assessments and 

technology assessment) confirm the 2000 finding and disagrees 

with the commenters that state otherwise. The EPA also agrees 

with the commenters that the 2000 finding was valid at the time 

it was made based on the CAA section 112(n)(1) studies and other 

information available to the Agency at that time. Furthermore, 

the EPA agrees with commenters that the final rule will lead to 

substantial reductions in HAP emissions from EGUs, that control 

of the HAP is estimated to lead to public health and 

environmental benefits as discussed in the RIA, that Hg 

emissions from U.S. EGUs pose a hazard to public health, and 
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that non-Hg HAP emissions from EGUs pose a hazard to public 

health.

Although these new analyses were not required, the EPA 

agrees with the commenters that stated that EPA is authorized to 

conduct additional analyses to confirm the 2000 finding. The EPA 

disagrees with the commenter’s assertion that the Agency is not 

authorized to consider new information and at the same time 

unable to use the information available in 2000 because, 

according to the commenter, that information is “stale.” Under 

this theory, the Agency could not ever make an appropriate and 

necessary finding prospectively, thereby excusing the Agency 

from its obligations to protect public health and the 

environment because it did not diligently act in undertaking its 

statutory responsibility to establish CAA section 112(d) 

standards within two years of listing EGUs. See CAA section 

112(c)(5). This is an illogical result that finds no basis in 

the statute. The EPA also disagrees with the commenter’s 

assertion that EPA may not consider new analyses conducted after 

the Utility Study in determining whether it is appropriate and 

necessary to regulate EGUs under section 112 for the reasons set 

forth in the preamble to the proposed rule.78

The EPA disagrees with the commenter’s implication that EPA 

conducted the new analyses because of alleged flaws in the 2000 

 

78 76 FR 24988.
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finding. As explained in detail in the preamble to the proposed 

rule, the 2000 finding was wholly valid and reasonable based on 

the information available to the Agency at that time, including 

the Utility Study. Further, the EPA maintains that had it 

complied with the statutory mandate to issue CAA section 112(d) 

standards within two years of listing EGUs, the EPA would likely 

have declined to conduct new analyses. The EPA conducted new 

analyses because over 10 years had passed since the 2000

finding, and EPA wanted to evaluate HAP emissions from U.S. EGUs 

based on the most accurate information available, though the 

Agency was not required to reevaluate the 2000 finding. In 

conducting the new analyses, the EPA used this updated 

information to further support the finding.

The EPA strongly disagrees with the commenter that stated 

that EPA failed to conform to the Information Quality Act. The 

EPA used peer reviewed information and quality-assured data in 

all aspects of the technical analyses used to support the 

appropriate and necessary finding supporting this regulation. In 

addition, the EPA submitted the Hg Risk TSD to the SAB for peer 

review, which “supports the overall design of and approach to 

the risk assessment and finds that it should provide an 

objective, reasonable, and credible determination of the 

potential for a public health hazard from mercury emitted from 
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U.S. EGUs.”

79 The SAB received the comments from Dr. Willie Soon, 

and had those comments available for consideration in their 

deliberations regarding the Hg risk analysis. The SAB 

specifically supported elements of the analysis criticized by 

Dr. Willie Soon regarding the use of the EPA RfD as a benchmark 

for risk and the connection between Hg emissions from U.S. EGUs 

and MeHg concentrations in fish. In addition, the risk 

assessment methodology for the non-Hg case studies is consistent 

with the methodology that EPA uses for assessments performed for 

Risk and Technology Review rulemakings, which underwent peer 

review by the SAB in 2009.80 During the public comment period, 

the EPA also completed a letter peer review of the methods used 

to develop inhalation cancer risk estimates for Cr and Ni 

compounds, and those reviews were generally supportive. See 

above description of this peer review. For the final rulemaking, 

the EPA revised both risk assessments consistent with 

recommendations from the peer reviewers. The EPA relies on the 

SAB’s review of the quality of the information supporting the 

analytical results. Accordingly, contrary to the commenters’

assertions, the EPA acted consistently with the Information 

Quality Act as well as EPA’s and OMB’s peer review requirements.

b. Hg Emissions Estimates

 

79 U.S. EPA-SAB, 2011.

80 U.S. EPA-SAB, 2010.
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1. Hg emissions from EGUs

Comment: The commenters addressed the 2005 and 2016 emissions

estimates for Hg and expressed concern that inaccuracies in 

these emissions estimates result in overestimates of risks from 

Hg deposition. Further, commenters compared EPA’s 2010 estimate 

and 2016 estimate, and stated that it is not possible for 29 

tons to be a correct inventory total for Hg emissions in both 

years given expected reductions from CSAPR. In addition, 

commenters specifically commented on assumptions included in the 

Integrated Planning Modeling (IPM), including a concern that Hg 

speciation factors used by IPM overestimate emissions in 2016. 

Other commenters noted that EGU sources are the predominant 

source of U.S. anthropogenic Hg emissions, particularly the 

oxidized and particulate forms of Hg that are of primary concern 

for Hg deposition.

Response: The EPA disagrees with commenters’ assertions that the 

EPA’s emissions estimates overestimate risk. While EPA agrees 

that the 2005 Hg emissions may be overestimated, such an 

overestimate in 2005 would actually lead to an underestimate of 

risk in 2016 and not an overestimate of risk, as claimed by the 

commenter, because the ratio approach used by EPA to scale fish 

tissue data would underestimate risk if 2005 Hg estimates were 

overestimated. Since the 2005 emissions are not used as a 
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starting point for 2016 emissions from IPM, any 2005 

overestimate does not affect the 2016 emissions levels. The 2016 

emissions are computed by IPM based on forecasts of demand, fuel 

type, Hg content of the fuel, and the emissions reductions 

resulting from each unit’s configurations. See IPM Documentation 

for further information, which is available in the docket. No 

commenter has provided any evidence that the IPM 2016 emissions 

projection methodology resulted in an overestimate.

The EPA acknowledges that the current Hg emissions estimate 

would not be the same as the 2016 Hg emissions estimate given 

that compliance with CSAPR is anticipated to have some Hg cobenefits. For this reason, the EPA reflected emission reductions 

anticipated from CSAPR in the Hg deposition modeling for 2016 in 

the Hg Risk TSD. In the final rule, the EPA revised the estimate 

of Hg emissions remaining from U.S. EGUs in 2016, which includes 

additional emission reductions anticipated from the final CSAPR. 

The revised estimate shows that U.S. EGUs would emit 27 tons of 

Hg in 2016. Although EPA does not use the current Hg emissions 

estimates in any of the risk calculations, the EPA estimates 

that current Hg emissions are 29 tons. Conclusions about the 

trend between current emissions and emissions in 2016 are 

limited by the fact that different methods were used to compute 
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the two estimates, as fully explained in the revised Emissions 

Overview memo in the docket.

The EPA disagrees with the commenter’s assertion that 

incorrect Hg emission factors result in incorrect 2016 

emissions. The 2016 projected Hg emissions are not based on 

emissions factors. The 2016 Hg emissions are computed by the IPM 

based on forecasts of demand, fuel type, Hg content of the fuel, 

and the emissions reductions resulting from each unit’s

configurations. The speciation factors referenced by the 

commenter provide a basis for the speciation of total projected 

Hg emissions into particulate, divalent gaseous, and elemental 

species, and do not impact the total amount of Hg emissions.

The EPA agrees with commenters who noted that EGU sources 

are the predominant source of U.S. anthropogenic Hg emissions, 

and in particular the oxidized and particulate forms of Hg that 

are of primary concern for Hg deposition.

2. Global Hg emissions

Comment: Several commenters stated that predicted Hg deposition 

relies heavily on the amount of gaseous elemental Hg used to 

define the boundary and initial conditions of a model, e.g., the 

Hg that enters the U.S. from outside the U.S. boundaries. The 

commenters asserted that this is especially important because Hg 

emissions from Asia—the region immediately upwind of North 
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America that affects U.S. Hg deposition significantly and also 

affects it the most compared to other regions—are expected to 

continue to increase.81,82,83,84,85,86 According to the commenter, 

this would affect the amount of Hg in the boundary and initial 

conditions. The commenters claim that EPA’s modeling did not 

account for these emission changes, thus leading to an 

overestimate of U.S. EGU-attributable deposition in 2016.

Several commenters noted that Hg emissions from U.S. EGUs 

are small when compared to global Hg emissions totals and 

natural sources within the U.S. These commenters used a variety 

of information to support alternative conclusions about the 

necessity to control U.S. EGU emissions to reduce Hg risk: 

 

81 Jaffe D., Prestbo E., Swartzendruber P., Weiss-Penzias P., 

Kato S., Takami A., Hatakeyama S., Kajii Y., 2005. “Export of 

Atmospheric Mercury from Asia,” Atmospheric Environment, 39, 

3029–3038.

82 Jaffe D., Strode S., 2008. “Fate and Transport of Atmospheric 

Mercury from Asia,” Environmental Chemistry, 5, 121. 

83 Pacyna E.G., Pacyna J.M., Sundseth K., Munthe J., Kindbom K., 

Wilson S., Steenhuisen F., Maxson P., 2010. “Global Emission of 

Mercury to the Atmosphere from Anthropogenic Sources in 2005 and 

Projections to 2020,” Atmospheric Environment, 44, 2487–2499.

84 Pirrone N., Cinnirella S., Feng X., Finkelman R.B., Friedli 

H.R., Leaner J., Mason R., Mukherjee A.B., Stracher G.B., 

Streets D. G., Telmer K., 2010. “Global Mercury Emissions to the 

Atmosphere from Anthropogenic and Natural Sources,” Atmospheric 

Chemistry and Physics, 10, 5951–5964.

85 Streets, D.G., Zhang, Q., Wu, Y., 2009. “Projections of Global 

Mercury Emissions in 2050.” Environmental Science & Technology

43, 2983-2988.

86 Weiss-Penzias P., Jaffe D., Swartzendruber P., Dennison J.B., 

Chand D., Hafner W., Prestbo E., 2006. “Observations of Asian 

Air Pollution in the Free Troposphere at Mt. Bachelor 

Observatory in the Spring of 2004,” Journal of Geophysical 

Research, 110, D10304.
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global Hg emissions inventories, global and regional 

photochemical modeling research, and observation-based 

assessments. A commenter stated that EPA has not acknowledged 

the dramatic decline in Hg emissions from U.S. EGUs since the 

late 1990s (approximately 50 percent) to the current level or 

consider the relative magnitude of Hg emissions from U.S. EGUs 

compared to other sources, natural (such as fires) and humancaused.

Response: The EPA disagrees that boundary and initial conditions 

used in modeling Hg deposition need adjustment for several 

reasons. First, the EPA does not use the first 10 days of the 

modeling simulation in the analysis, which is more than 

sufficient to remove the influence of initial conditions on Hg 

deposition estimates.87 Second, it is difficult to accurately 

characterize the speciation of Hg that flows into the U.S. from 

other countries due to the lack of data near the boundaries of 

the modeling domain. Third, the boundary inflow for the CMAQ Hg 

modeling used in the Hg deposition modeling are based on a 

global model GEOS-CHEM simulation using a 2000 based global 

 

87 Pongprueksa, P., Lin, C.J., Lindberg, S.E., Jang, C., 

Braverman, T., Bullock, O.R., Ho, T.C., Chu, H.W., 2008. 

“Scientific uncertainties in atmospheric mercury models III: 

Boundary and initial conditions, model grid resolution, and 

Hg(II) reduction mechanism.” Atmospheric Environment 42, 1828-

1845.
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inventory.88 A recently published comparison of global Hg 

emissions by continent for 2000 and 2006 found that total Hg 

emissions from Asia (and Oceania) total 1,306 Mg/yr in 2000 and 

1,317 Mg/yr in 2006.89 The EPA has determined that because the 

Asian Hg emissions estimated in this study are nearly constant 

between 2005 and 2006, any adjustments to the boundary 

conditions or adjustments to modeled Hg deposition would be 

invalid and inappropriate. Recent research has shown that 

ambient Hg concentrations have been decreasing in the northern 

hemisphere since 2000.90 Because emissions from Asia have not 

appreciably changed between 2000 and 2006 and ambient Hg 

concentrations have been decreasing, ENVIRON’s analysis contains 

incorrect assumptions and we need not address them further. For 

these reasons and the large uncertainties surrounding projected 

Hg global inventories, the EPA concludes that the most 

appropriate technical choice is to keep the Hg boundary 

conditions the same between the 2005 and 2016 simulations.

The EPA also disagrees with the commenters’ assertion that 

EPA has not acknowledged the decline in Hg emissions for the

 

88 Selin, N.E., Jacob, D.J., Park, R.J., Yantosca, R.M., Strode, 

S., Jaegle, L., Jaffe, D. 2007. “Chemical cycling and deposition 

of atmospheric mercury: Global constraints from observations.” 

Journal of Geophysical Research-Atmospheres 112.

89 Streets et al., 2009.

90 Slemr, F., Brunke, E.G., Ebinghaus, R., Kuss, J., 2011. 

“Worldwide trend of atmospheric mercury since 1995.” Atmospheric 

Chemistry and Physics 11, 4779-4787.
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U.S. EGUs since the late 1990s. The EPA analyzed historical, 

current, and future projected Hg emissions from the power 

generation sector, as cited in the preamble to the proposed 

rule. The EPA also disagrees with the commenters’ assertions 

that EPA failed to consider the relative magnitude of Hg 

emissions from U.S. EGUs compared to other sources. As noted in 

the Hg Risk TSD, the EPA modeled Hg emissions from U.S. and nonU.S. anthropogenic and natural sources to estimate Hg deposition 

across the country. The EPA also determined the contribution of 

Hg emissions from U.S. EGUs to total Hg deposition in the 

U.S. by running modeling simulations for 2005 and 2016 with Hg 

emissions from U.S. EGUs set to zero. Based on the Hg Risk TSD, 

Hg emissions from U.S. EGUs pose a hazard to public health based 

on the total of 29 percent of modeled watersheds potentially atrisk. Our analyses show that of the 29 percent of watersheds 

with population at-risk, in 10 percent of those watersheds U.S. 

EGU deposition alone leads to potential exposures that exceed 

the MeHg RfD, and in 24 percent of those watersheds, total 

potential exposures to MeHg exceed the RfD and U.S. EGUs 

contribute at least 5 percent to Hg deposition.

The commenters suggest that Hg emissions from U.S. EGUs 

represent a limited portion of the total Hg emitted worldwide, 

including anthropogenic and natural sources. While EPA 
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acknowledges that Hg emissions from U.S. EGUs are a small 

fraction of the total Hg emitted globally, it views the 

environmental significance of Hg emissions from U.S. EGUs and 

other domestic sources as a more germane consideration. Mercury 

is emitted from EGUs in three forms. Each form of Hg has 

specific physical and chemical properties that determine how far 

it travels in the atmosphere before depositing to the landscape. 

Although gaseous oxidized Hg and particle-bound Hg are generally 

local/regional Hg deposition concerns, all forms of Hg may 

deposit to local or regional watersheds. U.S. coal-fired power 

plants account for over half of the U.S. controllable emissions 

of the quickly depositing forms of Hg. Although emissions from 

international Hg sources contribute to Hg deposition in the 

U.S., the peer reviewed scientific literature shows that Hg 

emissions from U.S. EGUs in the U.S. significantly enhance Hg 

deposition and the response of ecosystems in the U.S.91,92,93,94

c. Hg Deposition Modeling

 

91 Caffrey et al., 2010.

92 Driscoll, C. T., Han, Y.-J., Chen, C. Y., Evers, D. C., 

Lambert, K. F., Holsen, T. M., et al. (2007). “Mercury 

Contamination in Forest and Freshwater Ecosystems in the 

Northeastern United States.” BioScience, 57(1).

93 Keeler, G.J., Landis, M.S., Norris, G.A., Christianson, E.M., 

Dvonch, J.T., 2006. “Sources of mercury wet deposition in 

Eastern Ohio, USA.” Environmental Science & Technology 40, 5874-

5881.

94 White, E.M., Keeler, G.J., Landis, M.S., 2009. “Spatial 

Variability of Mercury Wet Deposition in Eastern Ohio: 

Summertime Meteorological Case Study Analysis of Local Source 

Influences.” Environmental Science & Technology 43, 4946-4953.
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1. General Comments on Deposition Modeling

Comment: Several commenters stated that according to the ENVIRON 

report, the EPA overestimated U.S. EGU-attributable Hg 

deposition by 10 percent on average (and up to 41 percent in 

some areas). The commenters claim this overestimation is the 

result of boundary condition treatment, the exclusion of U.S. 

fire emissions,95 and Hg plume chemistry approach. In addition, 

one commenter referenced the same ENVIRON report and stated that 

before implementation of controls required by the proposed rule, 

areas with relatively high EGU-attributable Hg deposition (onefifth or more of total deposition) in 2016 constitute less than 

0.25 percent of the continental U.S. area, and only three grid 

cells have EGU contributions exceeding half of total deposition. 

Another commenter suggested that current research shows 

that models of Hg atmospheric fate and transport overestimate 

the local and regional impacts of some anthropogenic sources, 

such as U.S. EGUs. Thus, according to the commenter, calculated 

contributions to Hg deposition and fish tissue MeHg levels from 

these sources represent upper bounds of actual contributions,96,97

 

95 Finley, B.D., Swartzendruber, P.C., Jaffe, D.A., 2009. 

“Particulate mercury emissions in regional wildfire plumes 

observed at the Mount Bachelor Observatory.” Atmospheric 

Environment 43, 6074-6083.

96 Seigneur, C., Lohman, K., Vijayaraghavan, K., Shia, R.L., 

2003. “Contributions of global and regional sources to mercury 

deposition in New York State.” Environmental Pollution 123, 365-

373.
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and EPA should present results as estimates of lower and upper 

bound limits.

Response: The EPA disagrees with the information presented by 

ENVIRON. The ENVIRON report is based on the misapplication of 

multiple incommensurate modeling studies and false premises 

which include the incorrect notion that the boundary conditions 

are over-estimated and the idea that EPA should use in-plume 

chemistry that has not been explicitly characterized and peer 

reviewed. Reactions that may reduce gas phase oxidized Hg in 

plumes have not been explicitly identified in literature. Recent 

studies in central Wisconsin and central California suggest the 

opposite may happen; elemental Hg may be oxidized to Hg(II) in 

plumes.98,99 Better field study measurements and specific reaction 

mechanisms need to be identified before making conclusions about 

potential Hg in-plume chemistry or applying surrogate reactions 

in regulatory modeling. The possibility that Hg(0) is oxidized 

to Hg(II) in plumes suggests coal-fired power plant Hg 

 

97 Seigneur, C., Vijayaraghavan, K., Lohman, K., Karamchandani, 

P., Scott, C., 2004. “Modeling the atmospheric fate and 

transport of mercury over North America: power plant emission 

scenarios.” Fuel Processing Technology 85, 441-450.

98 Kolker, A., Olson, M.L., Krabbenhoft, D.P., Tate, M.T., Engle, 

M.A., 2010. “Patterns of mercury dispersion from local and 

regional emission sources, rural Central Wisconsin, USA.” 

Atmospheric Chemistry and Physics 10, 4467-4476.

99 Rothenberg, S.E., McKee, L., Gilbreath, A., Yee, D., Connor, 

M., Fu, X.W., 2010. “Wet deposition of mercury within the 

vicinity of a cement plant before and during cement plant 

maintenance.” Atmospheric Environment 44, 1255-1262.
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contribution inside the U.S. may be underestimated in EPA 

modeling. 

The EPA asserts that the numbers suggested by the commenter 

are inaccurate, as it is not appropriate to adjust EPA’s 

deposition estimates based on previous Hg modeling done with 

older Hg chemistry, in-plume reactions that have not been 

explicitly identified, and erroneous adjustments to Hg boundary 

inflow. Recent research has shown that ambient Hg concentrations 

have been decreasing in the northern hemisphere since 2000.100

The EPA declines to revise this analysis as commenter suggests 

for several reasons, including available evidence indicates that 

emissions from China have not appreciably changed between 2000 

and 2006101 and ambient Hg concentrations have decreased, the 

commenter inappropriately comingled out–of-date Hg modeling 

simulations with EPA results, and ENVIRON’s analysis has not 

undergone any scientific peer review and presents information 

with incorrect assumptions as noted in this response.

The EPA also disagrees with the commenter’s interpretation 

of the applicability of wildfire Hg emissions to this 

assessment. Finley et al. (2009)102 suggests caution when using 

their field data to make assumptions about Hg(p) emissions from 

wildfires; the estimated particulate Hg emissions from wildfires 

 

100 Slemr et al., 2011.

101 Streets et al., 2009.

102 Finley et al. 2009.
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is based on one field site with a limited sample size, and the 

assumptions made (such as the observed Hg(p) to carbon monoxide 

ratios at this location) may not be valid on a broader scale.103

Mercury emissions from wildfires are a re-volatilization of 

previously deposited Hg.104 Given that electrical generating 

power plants are currently and historically have been among the 

largest Hg-emitting sources, the inclusion of wildfire emissions 

in a modeling assessment would necessarily increase the 

contribution from this emissions sector.

The EPA disagrees with the assertion that EPA failed to 

consider the relative magnitude of Hg emissions from U.S. EGUs 

compared to other sources and disagrees with the interpretation 

of EGU deposition presented in the ENVIRON report. As noted in 

the Hg Risk TSD, the EPA modeled Hg emissions from U.S. and nonU.S. anthropogenic and natural sources to estimate Hg deposition 

across the country. The EPA also determined the contribution of 

Hg emissions from U.S. EGUs to total Hg deposition in the 

U.S. by running modeling simulations for 2005 and 2016 with Hg 

emissions from U.S. EGUs set to zero. Hg emissions from U.S. 

EGUs pose a hazard to public health based on the total of 29 

percent of modeled watersheds potentially at-risk. Our analyses 

 

103 Id.

104 Wiedinmyer, C., Friedli, H., 2007. “Mercury emission 

estimates from fires: An initial inventory for the United 

States.” Environmental Science & Technology 41, 8092-8098.
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show that of the 29 percent of watersheds with population atrisk, in 10 percent of those watersheds U.S. EGU deposition 

alone leads to potential exposures that exceed the MeHg RfD, and 

in 24 percent of those watersheds, total potential exposures to 

MeHg exceed the RfD and U.S. EGUs contribute at least 5 percent 

to Hg deposition. The ENVIRON report provides no risk analysis 

of EGU contribution. 

The EPA disagrees that research105,106 presented by the 

commenter shows that U.S. EGU impacts are over-estimated. The 

commenter’s references do not support this statement. The 

references provided by the commenter are based on Hg modeling 

that uses models that are no longer applied and that are based 

on out-dated Hg chemistry and deposition assumptions. Given the 

advances in Hg modeling since the early 2000s, the EPA does not 

believe an upper and lower bound estimate is necessary.

2. Chemical reactions

Comment: Several commenters stated that the CMAQ modeling fails 

to account for the chemical reduction of gaseous ionic Hg to 

elemental Hg that may occur in EGU plumes. The commenters noted 

that EPA did not use the Electric Power Research Institute’s 

(EPRI) Advanced Plume-in-Grid Treatment, which includes a 

surrogate reaction to reduce gaseous ionic Hg to elemental Hg 

 

105 Seigneur et al., 2003.

106 Seigneur et al., 2004.
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inside plumes. Multiple commenters claimed that the reduction of 

reactive gaseous Hg to gaseous elemental Hg has been reported in 

power plant plumes and that supporting data include atmospheric 

concentrations of speciated Hg measured downwind of power plant 

stacks at ground-level monitor sites and dispersion model 

predictions.107,108 A detailed description of various plume 

measurement studies is provided in EPRI Comments, Section 3.4: 

Plant Bowen, Georgia, Plant Pleasant, Wisconsin, and Plant 

Crist, Florida. One commenter believed the impact of grid 

resolution (12 km sized grid cells) on the CMAQ modeling was not 

appropriately addressed by EPA. Their concerns due to grid 

resolution include the notion that a source’s emissions will be 

averaged over the entire grid cell. According to the commenter, 

such averaging causes an artificially fast dilution that 

smoothes out areas of high and low deposition, which may limit 

the ability of the model to simulate smaller areas of localized 

high deposition. This commenter believed that using the APT 

would address these issues. 

Response: The EPA disagrees with the commenters’ claims that 

oxidized Hg chemically reduces to elemental mercury within the 

 

107 Edgerton, E.S., Hartsell, B.E., Jansen, J.J., 2006. “Mercury 

speciation in coal-fired power plant plumes observed at three 

surface sites in the southeastern U.S.” Environmental Science & 

Technology 40, 4563-4570.

108 Lohman, K., Seigneur, C., Edgerton, E., Jansen, J., 2006. 

“Modeling mercury in power plant plumes.” Environmental Science 

& Technology 40, 3848-3854.
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plume. There is no evidence of these chemical reactions in the 

scientific literature. The references cited by the commenters 

are from non-peer reviewed reports and conference proceedings. 

The EPA does not consider information presented at conferences 

or industry reports to be peer reviewed literature, and 

consideration of oral presentation material would be 

inappropriate. Further, even these cited references do not 

provide sufficient information for incorporating the supposed 

reactions into the modeling (e.g., specific chemical reactions, 

reaction rates, etc.); rather, the cited references only suggest 

that oxidized gas phase Hg could be reduced and postulate a 

possible pathway.

Recent studies in central Wisconsin and central California 

suggest the opposite may happen; elemental Hg may be oxidized to 

Hg(II) in plumes.109,110 Better field study measurements and 

specific reaction mechanisms need to be identified before making 

conclusions about potential Hg in-plume chemistry or applying 

surrogate reactions in regulatory modeling. Currently, models 

such as Advanced Plume Treatment (APT) use a surrogate reaction 

for the potential reactive gas phase Hg reduction that may or 

may not occur in plumes.111 Reactions that may reduce gas phase 

 

109 Kolker et al., 2010.

110 Rothenberg et al., 2010.

111 Vijayaraghavan, K., Seigneur, C., Karamchandani, P., Chen, 

S.Y., 2007. “Development and application of a multipollutant 
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oxidized Hg in plumes have not been explicitly identified in 

literature. The application of potentially erroneous in-plume 

chemistry that is a fundamental component of APT would be 

inappropriate. In addition, the APT is not available in the most 

recent version of CMAQ. It would be inappropriate for EPA to 

apply an out of date photochemical model with in-plume chemistry 

that has not been shown to exist.

The EPA agrees with the commenter that the CMAQ modeling 

with 12 km grid resolution may provide a lower bound estimate on 

EGU contribution as higher impacts using finer grid resolution 

are possible. The commenter’s assertion that EGU impacts are 

likely higher further supports the final conclusions of the 

exposure modeling assessment. The EPA notes that the application 

of a photochemical model at a 12 km grid resolution for the 

entire continental U.S. is more robust in terms of grid 

resolution and scale that anything published in literature and 

represents the most advanced modeling platform used for a 

national Hg deposition assessment.

3. Modeled deposition compared to measured deposition

Comment: Multiple commenters expressed dissatisfaction related 

to EPA’s model performance evaluation of CMAQ estimated Hg 

deposition. The commenters stated that EPA failed to evaluate 

 

model for atmospheric mercury deposition.” Journal of Applied 

Meteorology and Climatology 46, 1341-1353.
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the CMAQ model against real-world measurements and that EPA 

fails to provide first-hand information on wet and dry 

deposition processes. The commenters also stated that EPA needs 

to assess how predicted values of deposition compare to Mercury 

Deposition Network (MDN) data and how predicted values of 

ambient speciated Hg concentrations compare to measurement 

networks like AMNet and SEARCH. In addition, commenters stated 

that EPA used highly aggregated performance metrics comparing 

model estimates to observations that they believe result in a 

degraded and lenient operational evaluation of the modeling 

system. A commenter suggested that EPA’s model performance 

provides no confidence for the intended purpose of estimating 

deposition near point sources. One commenter simply noted that 

EPA’s model over-estimated total Hg wet deposition at MDN 

monitors. Finally, several commenters noted that EPA presented a 

negative modeled wet deposition total in the Air Quality 

Modeling TSD, which is physically impossible.

Response: EPA agrees with the commenters that the negative 

estimate for wet deposition in the Air Quality Modeling TSD was 

an error. This error reflected an incorrect calculation in the 

post-processing of model and observation pairs that only 

influenced the calculation of model performance metrics. The 

error has been fixed, and the model performance metrics in the 
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revised Air Quality Modeling TSD have been updated. This error 

did not affect Hg deposition. In response to comments, the EPA 

provided additional model performance evaluation by season to 

the revised Air Quality Modeling TSD. In addition, in response 

to comments, the EPA also included model performance evaluation 

for total Hg wet deposition for the 36 km modeling domain in the 

revised Air Quality Modeling TSD. 

The EPA disagrees that it did not conduct an assessment 

comparing CMAQ total Hg wet deposition estimates to MDN data. 

The Air Quality Modeling TSD clearly shows a comparison of CMAQ 

estimated total Hg wet deposition with MDN data for the entire 

length of the modeling period. The CMAQ wet deposition of Hg has 

been and will continue to be extensively evaluated against MDN

sites.112 There is no dry deposition monitoring network, which 

precludes evaluating CMAQ dry deposition processes. The EPA 

disagrees that an evaluation of ambient speciated Hg against 

routine monitor networks such as AMNet or SEARCH would be useful 

for this particular modeling application. The AMNet Hg network 

did not exist in 2005, which is EPA’s baseline model simulation 

time period, and the SEARCH network started making preliminary 

 

112 Bullock, O.R., Atkinson, D., Braverman, T., Civerolo, K., 

Dastoor, A., Davignon, D., Ku, J.Y., Lohman, K., Myers, T.C., 

Park, R.J., Seigneur, C., Selin, N.E., Sistla, G., 

Vijayaraghavan, K., 2009. “An analysis of simulated wet 

deposition of mercury from the North American Mercury Model 

Intercomparison Study.” Journal of Geophysical ResearchAtmospheres 114.
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measurements of Hg at one or two sites in 2005. In addition, 

measurement artifacts related to gaseous oxidized Hg are 

difficult to quantify and make direct comparison to model 

estimates problematic.113 Considering the problems associated 

with TEKRAN measurements of ambient Hg and the sparse nature of 

routine measurements in the U.S., the EPA did not compare 

ambient Hg against model estimates. 

The EPA disagrees that the model performance presented in 

the air quality TSD is insufficient. The EPA asserts that the 

model performance evaluation is generally similar to the level 

of model performance presented in literature. One commenter 

presented the results of several Hg modeling studies as 

providing information that the commenter believes to be relevant 

for this assessment in terms of model performance metric 

estimation and the level of model performance evaluation shown 

for assessments modeling Hg near point sources. For example, one 

cited study titled “Modeling Mercury in Power Plant Plumes”

models near-source Hg chemistry from U.S. EGUs, but provides 

absolutely no information about model performance evaluation.114

Another commenter identified two studies as supposedly 

having Hg modeling results that are applicable to EPA’s 

 

113 Lyman, S.N., Jaffe, D.A., Gustin, M.S., 2010. “Release of 

mercury halides from KCl denuders in the presence of ozone.” 

Atmospheric Chemistry and Physics 10, 8197-8204.

114 Lohman et al., 2006.
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analysis.115,116 These studies present similar model performance 

metrics as EPA. The EPA disagrees that the Agency used “highly 

aggregated performance metrics” that result in degraded and 

lenient model evaluation. The studies presented117,118 as relevant 

for point source mercury modeling use an approach to aggregate 

the operational performance metrics across many monitor 

locations as did EPA; however, these articles calculate long 

term annual averages of modeled and observed total Hg wet 

deposition before estimating performance metrics. It is common 

practice to pair modeled estimates and observations in space and 

time (weekly in this case) and estimate performance metrics, 

then average all the metrics together. The latter is the 

approach taken by the EPA and should have been taken by the 

studies presented by the commenter. The EPA used a more 

stringent approach to match observations and predictions and 

aggregation of operational model performance. The EPA agrees 

 

115 Seigneur, C., Lohman, K., Vijayaraghavan, K., Jansen, J., 

Levin, L., 2006. “Modeling atmospheric mercury deposition in the 

vicinity of power plants.” Journal of the Air & Waste Management 

Association 56, 743-751.

116 Vijayaraghavan, K., Karamchandani, P., Seigneur, C., Balmori, 

R., Chen, S.-Y., 2008. “Plume-in-grid modeling of atmospheric 

mercury.” Journal of Geophysical Research-Atmospheres 113.

117 Seigneur, C., Lohman, K., Vijayaraghavan, K., Jansen, J., 

Levin, L., 2006. “Modeling atmospheric mercury deposition in the 

vicinity of power plants.” Journal of the Air & Waste Management 

Association 56, 743-751.

118 Vijayaraghavan, K., Karamchandani, P., Seigneur, C., Balmori, 

R., Chen, S.-Y., 2008. “Plume-in-grid modeling of atmospheric 

mercury.” Journal of Geophysical Research-Atmospheres 113.
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that the commenter accurately restated total wet deposition 

model performance information provided by the EPA in the Air 

Quality Modeling TSD. To provide context, other Hg modeling 

studies show a positive bias for annual total Hg wet 

deposition.119,120 An annual Hg modeling application done by 

ENVIRON121 and the Atmospheric and Environmental Research for 

Lake Michigan Air Directors Consortium show seasonal average 

normalized bias between 70 and 158 percent and seasonal average 

normalized error between 72 and 503 percent.122 These results 

indicate a very large over-estimation tendency. The model 

performance shown by EPA is consistent with other long-term Hg 

modeling applications.

4. Excess Local Deposition from Hg Emissions from U.S. EGUs

(Deposition Hotspots)

Comment: One commenter stated that reducing Hg will benefit 

local environments. The commenter stated that a 2007 study 

confirmed the presence of Hg “hotspots” downwind from coal-fired 

power plants and confirmed that coal-fired power plants within 

 

119 Id.

120 Vijayaraghavan et al., 2007.

121 Yarwood, G, Lau, S., Jia, Y., Karamchandani, P., 

Vijayaraghavan, K. 2003. Final Report: Modeling Atmospheric 

Mercury Chemistry and Deposition with CAMx for a 2002 Annual 

Simulation. Prepared for Wisconsin Department of Natural 

Resources. 

http://www.gypsymoth.wi.gov/air/toxics/mercury/hg_X97579601_appB

.pdf

122 Yarwood et al., 2003.
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the U.S. are the primary source of Hg to the Great Lakes and the 

Chesapeake Bay.123 The commenter also stated that the study is 

consistent with a major Hg deposition study conducted by the EPA 

and the University of Michigan that concluded that approximately 

70 percent of Hg wet deposition resulted from local fossil fuel 

emissions in the region.124

One commenter agreed with the Agency’s assessment of the 

potential for deposition “hotspots” that shows that Hg 

deposition near EGUs can be three times as large as the regional 

average. The commenter stated that this excess Hg deposition 

would substantially increase the health and environmental risks 

associated with emissions at these sites. The same commenter 

also stated that EPA applied a conservative methodology to 

quantify near-source Hg deposition. The commenter stated that 

maximum excess local Hg deposition may be significantly 

underestimated by averaging high deposition sites downwind of an 

EGU in the direction of prevailing winds with lower excess 

deposition at locations close to but frequently upwind of the 

facility. The same commenter suggests that had EPA used CMAQ and 

individual 12x12 km2 grid cells to quantify local deposition, the 

 

123 Evers, David C. et al. 2007. “Biological Mercury Hotspots in 

the Northeastern United States and Southeastern Canada,” 

Bioscience. Vol. 57 No. 1. p. 29.

124 Cohen, et al. 2004. “Modeling the Atmospheric Transport and 

Deposition of Mercury to the Great Lakes,” Environmental 

Research 95, (247-265).
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model could increase the excess Hg deposition at these locations 

significantly and place them at even greater risk of adverse 

health and environmental effects of HAP from U.S. EGUs. 

One commenter stated that the Hubbard Brook Research 

Foundation issued a report in 2007 that identified five Hg 

hotspots, one of which was in the Adirondack Park, along with 

four suspected hotspots.125 The commenter stated that this study 

also provides a good description of the impacts of Hg on the 

Common Loon, which is a symbol of a healthy Adirondack 

environment.

One commenter stated that there is there is no evidence of 

Hg hotspots due to local deposition associated with coal-fired 

power plants. According to the commenter, the EPA’s use of a 50 

km radius to calculate hotspots is flawed. The commenter stated 

that modeling studies show that deposition of Hg emitted from 

power plants is not confined to a 50-km radius around the plants 

and that most emissions from power plants travel beyond 50 km.126

Several commenters stated that the EPA does not adequately 

define hotspots in this proposed rule. Those same commenters 

cited a previous EPA definition of hotspots as “a waterbody that 

 

125 Driscoll, C.T., D. Evers, K.F. Lambert, N. Kamman, T. Holsen, 

Y-J. Han, C. Chen, W. Goodale, T. Butler, T. Clair, and R. 

Munson. Mercury Matters: Linking Mercury Science with Public 

Policy inthe Northeastern United States. 2007. Hubbard Brook 

Research Foundation. Science Links Publication. Vol. 1, no. 3.

126 Seigneur et al., 2006.
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is a source of consumable fish with MeHg tissue concentrations, 

attributable solely to utilities, greater than EPA’s MeHg water 

quality criterion of 0.3 mg/kg” (milligrams per kilogram).127 The 

same commenters stated that it is unclear why EPA changed from 

defining a hotspot by fish tissue MeHg concentration to defining 

a hotspot by depositional excess. Two commenters suggested that 

a Hg hotspot is a specific location that is characterized by 

elevated concentrations of Hg exceeding a well-established 

criterion, such as a reference concentration (RfC) when compared 

to its surroundings. Those same commenters stated that 

identifying Hg hotspots should not be constrained to locations 

where concentrations can be attributed to a single source or 

sector.128 One of those two commenters noted that others have 

defined “hotspots as a spatially large region in which 

environmental concentrations far exceed expected values, with 

such values (i.e. concentrations) being 2 to three standard 

deviations above the relevant mean.”

129

 

127 U.S. EPA, 2005. 40 CFR Part 63 [OAR–2002–0056; FRL–7887–7] 

RIN 2060–AM96. Revision of December 2000 Regulatory Finding on the 

Emissions of Hazardous Air Pollutants From Electric Utility 

Steam Generating Units and the Removal of Coal- and Oil-Fired 

Electric Utility Steam Generating Units From the Section 112(c). 

Final rule, March 29.

128 Evers et al., 2007.

129 Sullivan T., 2005. “The Impacts of Mercury Emissions from 

coal-fired Power Plants on Local Deposition and Human Health 

Risk.” Presented at the Pennsylvania Mercury Rule Workgroup 

Meeting, October 28.
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One commenter stated that Hg concentrations are not always 

highest at sites closest to a major source. The commenter 

referred to a study130 that demonstrated that concentrations of 

atmospheric reactive gaseous Hg, gaseous elemental Hg, and fine 

particulate Hg were lower when measured 25 km from a 1,114 MW 

coal-fired EGU than when measured 100 km away. The commenter 

stated that these findings contradict the idea, implicit in 

EPA’s hotspot analysis, that reactive gaseous Hg decreases with 

distance from a large point source.

One commenter provided information from a non-peer reviewed 

report with wet Hg deposition measurements downwind from the 

coal-fired power plant Crist in Pensacola, FL. The commenter 

stated that using the same data from these same wet deposition 

sites, one study131 found that Hg wet deposition and 

concentrations did not differ in a statistically significant 

manner among these three sites and that the concentrations 

values were similar to those from Mercury Deposition Network 

(MDN) sites that are more than 50 km away from Plant Crist 

located along the Northern Gulf of Mexico coast. 

 

130 Kolker, et al., 2010.

131 Caffrey, J.M., Landing, W.M., Nolek, S.D., Gosnell, K.J., 

Bagui, S.S., Bagui, S.C., 2010. “Atmospheric deposition of 

mercury and major ions to the Pensacola (Florida) watershed: 

spatial, seasonal, and inter-annual variability.” Atmospheric 

Chemistry and Physics 10, 5425-5434.
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Another commenter stated that Plant Crist installed a wet 

scrubber and has operated that scrubber continuously since 

December 2009. The commenter stated that the scrubber reduces 

total Hg emissions by about 70 percent and reduces emissions of 

reactive gaseous Hg by about 85 percent. The commenter cited a 

non-peer reviewed conference presentation132 that reported 

changes in Hg wet deposition relative to historic measurements. 

The commenter stated that, taken collectively, these findings 

show that increased local total Hg deposition, possibly due to 

EGUs, and deposition changes due to changes in EGU emissions, 

are small.

Two commenters stated that a study by the Department of 

Energy (DOE) that collected and analyzed soil and vegetation 

samples for Hg near three U.S. coal-fired power plants – one in 

North Dakota, one in Illinois, and one in Texas – found no 

strong evidence of “hotspots” around these three plants. 

Two commenters stated that analysis of long-term trends in 

Hg emissions from coal-fired EGUs and wet deposition in Florida 

concluded that statistical analysis does not show evidence of a 

significant relationship between temporal trends in Hg emissions 

 

132 Krishnamurthy N., Landing W.M, Caffrey J.M., 2011. “Rainfall 

Deposition of Mercury and Other Trace Elements to the Northern 

Gulf of Mexico.” Presented at the 10th International Conference 

on Mercury as a Global Pollutant, Halifax, Nova Scotia, Canada, 

July 27.
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from coal-fired EGUs in Florida and Hg concentrations in 

precipitation during 1998 to 2010.

Two commenters stated that the Hg Risk TSD presents no 

information, summary statistics, and/or actual calculations 

showing how excess deposition within 50 km of an EGU source is 

obtained. The commenters stated that by assessing only Hg 

deposition attributable to EGUs, the EPA fails to provide a 

context for all other sources of Hg deposition. The commenters 

stated that the Agency does not explain why deposition from the

top 10 percent of EGU Hg emitters does not decline, despite 

substantial reductions in modeled Hg emissions from those 

sources between 2005 and 2016. According to the commenters this 

implies that the top 10 percent EGUs may have approximately as 

much of a regional effect as a local effect. 

Two commenters stated that the CMAQ model has limitations 

when used to predict local deposition and tends to overestimate 

local deposition. The commenters stated that modeling studies 

using either a plume model or an Eulerian model predict that 91 

to 96 percent of the Hg emitted by an EGU travels beyond 50 

km.133

Response: The EPA agrees with the commenters that stated that Hg 

emissions from EGUs deposit locally and regionally and 

contribute to excess local deposition near U.S. EGUs. The EPA 

 

133 Edgerton et al., 2006.
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acknowledges additional studies134 cited by those commenters that 

corroborate EPA’s conclusions. However, the EPA disagrees with 

those commenters’ characterization of the methodology used to 

calculate the potential for excess local deposition. In 

response, the EPA has clarified the methodology in the new TSD 

entitled “Technical Support Document: Potential for Excess Local 

Deposition of U.S. EGU Attributable Mercury in Areas near U.S. 

EGUs,” which is available in the docket.

The EPA agrees that there is no generally agreed-upon 

definition of “hotspot.” As discussed in the preamble and TSD, 

for the purposes of the appropriate and necessary finding, the 

EPA determined that information on the potential for excess 

deposition of Hg in areas surrounding power plants would be 

useful in informing the finding. The EPA disagrees with some 

commenters who misinterpreted the intent of the Hg deposition 

hotspot analysis. Specifically, the analysis is not of “Hg 

hotspots”, which are often defined as high Hg concentration in 

fish, but rather of Hg deposition hotspots, defined as excess 

local Hg deposition around U.S. EGUs, as clarified in the new 

Local Deposition TSD. Because EPA did not identify “Hg hotspots”

of high Hg concentrations in fish, the EPA’s MeHg water quality 

criterion of 0.3 mg/kg is irrelevant to EPA’s analysis of excess 

local Hg deposition for this rule.

 

134 Driscoll et al., 2007.
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The EPA disagrees that the analysis assumes that deposition 

of Hg is confined to a 50-km radius around power plants. The 

purpose of the EPA’s analysis was to evaluate whether there 

existed” excess deposition of Hg in nearby locations within 50 

km of EGUs that might result in Hg deposition ‘hotspots’.” As 

explained further in the new TSD, the EPA calculated the average 

EGU-attributable deposition (based on CMAQ modeling of Hg 

deposition) in the area 500 km around each plant and the average 

EGU-attributable deposition in the area 50 km around each plant. 

The difference between those two values is the excess local 

deposition around the plant. The EPA does not suggest Hg 

emissions from power plants stop at 50 km from the source. Some 

portion of EGU emissions deposit before 50 km, and some portion 

travels beyond 50 km. In addition, Hg disperses as it 

transports, so the average EGU contribution can be lower in 

areas beyond 50km relative to areas within 50km even though Hg 

emissions from EGUs are depositing into U.S. watersheds.

The EPA disagrees with some commenters’ interpretation of 

the analysis as being focused on local deposition from all 

sources. In fact, the focus was on excess local deposition, 

rather than all local deposition. The EPA has clarified the 

purpose of the excess local deposition analysis in the new TSD. 

The EPA agrees that all EGUs add to local deposition, however, 
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not all EGUs have local deposition that greatly exceeds regional 

deposition, which is the relevant question. The EPA disagrees 

that the DOE study referenced by the commenters attempted to 

assess the same analytical question as EPA’s analysis. The DOE 

study focused on comparisons of total deposition near and far 

from power plants. The EPA’s analysis did not focus on total Hg 

deposition, because as EPA acknowledges throughout its analysis, 

global sources of Hg deposition account for a large percentage 

of total Hg deposition. In addition, including global sources of 

Hg deposition would obscure the comparison of local and regional 

U.S. EGU-attributable Hg deposition. Because of regional 

deposition from both domestic and global sources of Hg, total Hg 

deposition at any location is unlikely to be highly correlated 

with local sources. The EPA’s analysis focused on U.S. EGUattributable Hg deposition and demonstrates that for some plants 

(especially those with high Hg emissions), there is local 

deposition of Hg that exceeds the average regional deposition 

around the plant. 

The EPA’s analysis shows heterogeneity in the amount of 

excess local deposition around plants. The new Local Deposition 

TSD shows that some plants can have local deposition that is 

less than the regional average deposition, suggesting that most 

of the Hg from those plants is transported regionally or that 
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other EGUs in the vicinity of those plants dominate the 

deposition of Hg near the plants. This does not detract from the 

overall finding that around some power plants with high levels 

of Hg emissions excess local deposition is on average three 

times the regional EGU-attributable deposition around those 

plants. 

The EPA disagrees that the Hg Risk TSD did not provide 

sufficient information regarding the excess local deposition 

calculation. Nonetheless, the EPA has further clarified the 

methodology in the new Local Deposition TSD, including further 

descriptions of the method used to calculate the local and 

regional deposition around power plants along with maps and 

tables of results.

The EPA disagrees with the commenters that stated that the 

discussion of local deposition in the Hg Risk TSD did not 

demonstrate that Hg deposition from the top 10 percent of EGU Hg 

emitters declines. Table 1 of the new Local Deposition TSD 

clearly shows that mean local deposition (within 50km of a 

plant) for the top 10 percent of emitters declines from 4.89 

micrograms per cubic meter (μg/m3) to 1.18 μg/m3. What does not 

change is the percent local excess for EGU-attributable Hg 

deposition. This implies that while Hg deposition from EGUs is 

declining, there is still an excess contribution to local 
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deposition relative to regional deposition; e.g., because of 

dispersion, the contribution to average deposition outside 50 km 

from the plant is lower than the contribution to average 

deposition within 50 km of the plant.

The EPA disagrees that the information135 provided by the 

commenter regarding the Crist plant and other coal-fired power 

plants in Florida is relevant to EPA’s analysis of excess local 

deposition from U.S. EGUs because it is based on measurements of 

wet Hg deposition without consideration of dry Hg deposition, 

which can be a significant component of Hg deposition. 

The EPA disagrees with the commenter regarding the 

interpretation of the literature related to the spatial extent 

of deposition of Hg emitted by U.S. EGUs. The EPA also disagrees 

that the peer-reviewed CMAQ model has limitations for this 

application or overestimates local deposition. The commenter 

does not provide any credible support for the assertion that 

grid-based models typically overestimate local deposition 

surrounding EGUs. The EPA maintains that the CMAQ photochemical 

model represents the best science currently available in 

simulating atmospheric chemistry, transport, and deposition 

processes. 

 

135 EPRI, 2010.
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The study136 cited by the commenter to support the notion 

that 91 to 96 percent of Hg emitted from power plants travels 

beyond 50 km is based on a photochemical transport model (the 

TEAM model) that does not employ current state-of-the-science 

and is not actively developed or updated. Furthermore, the 

modeling is based on grid cells that are 20 km in size, which 

limits generalizability to EPA modeling performed at 12 km grid 

resolution using a state of the science photochemical grid 

model. The cited modeling study ignores dry deposition of 

elemental Hg from all sources, an assumption that clearly limits 

the regional impacts from sources.137 The methodology of this 

study cited by the commenter is critically flawed in that it 

presents no results where individual Hg emission sources are 

removed and the difference between the zero out simulation 

(where emissions from U.S. EGUs are set to zero) and the 

baseline model simulations are directly compared. Finally, the 

modeling study cited by the commenter presents an illustration 

of gridded total annual Hg deposition from the TEAM model for 

the eastern U.S. that clearly shows elevated annual total Hg 

deposition in the vicinity of coal-fired power plants in the 

Ohio River Valley and northeast Texas.

d. Hg Risk TSD

 

136 Seigneur et al., 2006.

137 Id.
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1. Assumption of Linear Proportionality in Relationship between 

Changes in Hg Deposition and Changes in Fish Tissue Hg 

Concentrations (Mercury Maps)

Comment: Several commenters criticized EPA’s assumption that 

changes in deposition resulting from U.S. EGU emissions of Hg 

will result in proportional changes in fish tissue Hg 

concentrations at the watershed level, as supported by the 

Mercury Maps modeling exercise. According to one commenter, the 

Mercury Maps model has limited capability to adequately 

determine bioaccumulation in fish. The same commenter stated 

that the Mercury Cycling Model (MCM) developed by EPRI is a more 

rigorous model that was developed expressly to evaluate the 

relationship between changes in atmospheric Hg deposition to 

waterbodies and changes in fish tissue MeHg levels.

Several commenters stated that the Mercury Maps model has 

many deficiencies. Those commenters stated that Mercury Maps is 

a static model unable to account for the dynamics of ecosystems 

that affect Hg bioaccumulation in fish, cannot consider non-air 

Hg inputs to watersheds, and assumes reductions in airborne Hg 

lead to proportional reductions in fish MeHg concentrations. 

Another commenter claimed that data that demonstrate a steadystate linear reduction in fish tissue MeHg in response to a 

reduction in atmospheric Hg deposition within watersheds do not 
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exist and provided several references that they claimed show 

non-linear responses to changes in Hg deposition.138,139

The same commenter disagreed with EPA’s interpretation of 

Figure 2-17 in the March TSD and stated that a U.S. Geological 

Survey national waterway study140 showed that sheet flow and 

drainage, not deposition, dominated input to the waterbodies it 

surveyed. The commenter stated that sheet flow and drainage 

could contain Hg and thus complicate the relationship that EPA 

asserts is linear and direct. Another commenter cited Figure 2-

17 in the Hg Risk TSD as showing that there is no well-defined 

relationship between Hg deposition and MeHg concentrations in 

fish tissue on a national basis. 

 

138 Harris., R. C., John W. M. Rudd, Marc Amyot, Christopher L. 

Babiarz, Ken G. Beaty, Paul J. Blanchfield, R. A. Bodaly, Brian 

A. Branfireun, Cynthia C. Gilmour, Jennifer A. Graydon, Andrew 

Heyes, Holger Hintelmann, James P. Hurley, Carol A. Kelly, David 

P. Krabbenhoft, Steve E. Lindberg, Robert P. Mason, Michael J. 

Paterson, Cheryl L. Podemski, Art Robinson, Ken A. Sandilands, 

George R. Southworth, Vincent L. St. Louis, and Michael T. 

TateRudd, J. W. M., Amyot M., et al., Whole-Ecosystem study 

Shows Rapid Fish-Mercury Response to Changes in Mercury 

Deposition. Proceedings of the National Academy of Sciences 

Early Edition, PNAS 2007 104 (42) pp. 16586-16591; (published 

ahead of print September 27, 2007).

139 Orihel D.M., Paterson M.J., Blanchfield P.J., Bodaly R.A., 

Gilmour C.C., Hintelmann H., 2007. “Temporal Changes in the 

Distribution, Methylation, and Bioaccumulation of Newly 

Deposited Mercury in an Aquatic Ecosystem,” Environmental 

Pollution, 154, 77–88. 

140 Scudder B.C., Chasar L.C., Wentz D.A., Bauch N.J., Brigham 

M.E., Moran P.W., Krabbenhoft D.P., 2009. Mercury in fish, bed 

sediment, and water from streams across the United States, 1998–

2005: U.S. Geological Survey Scientific Investigations Report 

2009–5109, 74 p.
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Several commenters provided comments related to the 

assumption that fish tissue Hg levels used in the analysis 

represent a steady-state. One commenter stated that given the 

demonstrated lag time in response to deposition change, it is 

logical to conclude that a lag time needs to be incorporated in 

Mercury Maps to adjust the estimation of how much fish tissue 

MeHg levels decrease in response to decreases in Hg deposition 

attributable to U.S. EGUs. According to the same commenter, the 

METAALICUS study shows that there is a lag time (and a nonproportional response) after 3–4 years. The same commenter noted 

that there are numerous factors that influence lag time 

including (1) watershed characteristics,141 (2) the fact that 

watersheds may act as legacy sources releasing Hg when 

disturbed,142 (3) the magnitude of emission reductions and 

subsequent changes in atmospheric deposition need to be weighed 

against the amount of Hg already in an ecosystem,143 (4) the 

 

141 Grigal D.F., 2002. “Inputs and Outputs of Mercury from 

Terrestrial Watersheds: A Review,” Environmental Review, 10, 1–

39. 

142 Yang H., Rose N.L., Battarbee R.W., Boyle J.F., 2002. 

“Mercury and Lead Budgets for Lochnagar, a Scottish Mountain 

Lake and Its Catchment,” Environmental Science & Technology, 36, 

1383–1388.

143 Krabbenhoft D.P., Engstrom D., Gilmour C., Harris R., Hurley 

J., Mason R., 2007. Monitoring and Evaluating Trends in Sediment 

and Water Indicators. In Harris R., Krabbenhoft D., Mason R., 

Murray M.W., Reash R., Saltman T. (Eds.), Ecosystem Responses to 

Mercury Contamination: Indicators of Change. New York: Society 

of Environmental Toxicology and Chemistry (SETAC) North America 

Workshop on Mercury Monitoring and Assessment, CRC, pp. 47–87.
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distance of an ecosystem from Hg sources,144 and (5) the fact 

that Hg deposited to aquatic ecosystems becomes less available 

for uptake by biota over time.145 Another commenter stated that 

additional Mercury Maps assumptions do not allow for 

considerations of lag in response to changes in: (1) deposition, 

(2) legacy sources of Hg such as mining, (3) historical Hg 

deposition, (4) natural Hg levels in fish, (5) ecosystem 

dynamics over time, or (6) the relative source contributions 

over time. Another commenter stated that lag times need to be 

included in the modeling and be able to vary from watershed to 

watershed and sometimes even from waterbody to waterbody within 

a watershed. Several commenters stated that the emission rates 

of Hg due to U.S. sources have been decreasing for more than a 

decade, while emissions due to sources outside the U.S. have 

been increasing. For this reason, the commenter asserted that 

the system is not at steady-state, a basic premise of the model. 

Another commenter stated that while the time lag for deposition 

to reach a waterbody is mentioned in the Hg Risk TSD, there is 

 

144 Lindberg S. et al. 2007. “A synthesis of progress and 

uncertainties in attributing the sources of mercury in 

deposition.” Ambio 36(1): 19-32.

145 Orihel D.M., Paterson M.J., Blanchfield P.J., Bodaly R.A., 

Hintelmann H., 2008. “Experimental Evidence of a Linear 

Relationship between Inorganic Mercury Loading and Methylmercury 

Accumulation by Aquatic Biota,” Environmental Science & 

Technology, 41, 4952–4958.
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no discussion of the fact that a portion of the deposition is 

unlikely to reach the water at all. 

One commenter believes EPA incorrectly implied that its EGU 

risk estimates using Mercury Maps are underestimated because 

they do not account for legacy EGU-attributable deposition, 

which EPA assumes to be higher. 

One commenter stated that while EPA properly screened out 

watersheds with significant current non-air sources of Hg, the 

EPA did not adequately screen out watersheds with significant Hg 

contributions from non-air sources, specifically watersheds with 

historic Hg or gold mining or other industrial Hg discharges. 

The same commenter stated that EPA’s study was not 

geographically balanced and was dominated by rivers in the 

coastal region of the southeast that has numerous wetlands, 

which are favorable locations for methylation and have 

conditions that are not typical of much of the rest of the U.S.

Response: The EPA disagrees with the commenters who challenged 

the assumption of a linear proportional relationship between 

changes in U.S. EGU deposition and fish tissue Hg levels. The 

EPA specifically asked the SAB to evaluate EPA’s assumption of 

linear proportionality in the relationship between Hg deposition 

and fish tissue MeHg concentrations, supported by the Mercury 

Maps analysis. The SAB peer review committee provided the 
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following overall response, which generally supports EPA’s 

approach:

The SAB agrees with the Mercury Maps approach used in 

the analysis and has cited additional work that 

supports a linear relationship between mercury loading 

and accumulation in aquatic biota. These studies 

suggest that mercury deposited directly to aquatic

ecosystems can become quickly available to biota and 

accumulated in fish, and reductions in atmospheric 

mercury deposition should lead to decreases in 

methylmercury concentrations in biota. The SAB notes 

other modeling tools are available to link deposition 

to fish concentrations, but does not consider them to 

be superior for this analysis or recommend their use. 

The integration of Community Multiscale Air Quality 

Modeling System (CMAQ) deposition modeling to produce 

estimates of changes in fish tissue concentrations is 

considered to be sound. Although the SAB is generally 

satisfied with the presentation of uncertainties and 

limitations associated with the application of the 

Mercury Maps approach in qualitative terms, it 

recommends that the document include quantitative 
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estimates of uncertainty available in the existing 

literature.146

The SAB peer review committee specifically addressed the 

MCM suggested by the commenter and had the following response:

The SAB agrees with the application of Mercury Maps in 

this assessment. There are other modeling tools 

capable of making a national scale assessment, such as 

the Regional Mercury Cycling Model (R-MCM). However, 

the R-MCM is more data intensive and the results 

produced by the two model approaches should be 

equivalent.

The R-MCM, a steady-state version of the timedependent Dynamic Mercury Cycling Model, has been 

publicly available to and used by the EPA (Region 4, 

Athens, Environmental Research Laboratory) for a 

number of years. R-MCM requires more detail on water 

chemistry, methylation potential, etc., and yields 

more information as well. Substantial data support the 

Mercury Maps and the R-MCM steady-state results, so 

that the results of the sensitivity analysis and the 

outcomes from using the alternative models would be 

equivalent between the two modeling approaches. Though 

running an alternative model framework may provide 

 

146 U.S. EPA-SAB, 2011.
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additional reassurance that the Mercury Maps “base 

case” approach is a valid one, it is unlikely that 

substantial additional insight would be gained with 

the alternative model framework.147

In addition, the SAB stated, “Since the Mercury Maps 

approach was developed, several recent publications have 

supported the finding of a linear relationship between mercury 

loading and accumulation in aquatic biota.148,149,150 These studies 

suggested that mercury deposited directly to aquatic ecosystems 

can become quickly available to biota and accumulated in fish, 

and that reductions in atmospheric mercury deposition should 

lead to decreases in methylmercury concentrations in biota. 

These results substantiate EPA’s assumption that proportionality 

between air deposition changes and fish tissue methylmercury 

level changes is sufficiently robust for its application in this 

risk assessment.”

151

Based on the responses of the SAB peer review committee, 

the EPA’s use of the linear proportionality assumption, 

supported by the Mercury Maps analysis, is well-supported.

The EPA also disagrees with commenters’ interpretation of 

Figure 2-17. As stated in the Hg Risk TSD, while this figure is 

 

147 U.S. EPA-SAB, 2011.

148 Orihel et al., 2007. 

149 Orihel et al., 2008.

150 Harris et al., 2007. 

151 U.S. EPA-SAB, 2011. 
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useful to demonstrate the lack of correlation across watersheds 

between total deposition of Hg and MeHg concentrations in fish 

tissue, it is not indicative of the likely correlation between 

changes in Hg deposition at a given watershed and changes in 

MeHg concentrations in fish tissue from that watershed. The SAB 

agreed with this interpretation, noting the importance of Figure 

2-17 demonstrating that “spatial variability of deposition rates 

is only one major driver of spatial variability of fish 

methylmercury and that variability of ecosystem factors that 

control methylation potential (especially wetlands, aqueous 

organic carbon, pH, and sulfate) also play a key role.”

152

In response to recommendations from the SAB, the EPA 

expanded the discussion of uncertainties associated with the 

linearity assumption, including uncertainties related to the 

potential for sampled fish tissue Hg level to reflect previous 

Hg deposition and the potential for non-air sources of Hg to 

contribute to sampled fish tissue Hg levels. Each of these 

sources of uncertainty may result in potential bias in the 

estimate of exposure associated with current deposition. The EPA 

took steps to minimize the potential for these biases by 1) only 

using fish tissue Hg samples from after 1999, and 2) screening 

out watersheds that either contained active gold mines or had 

other substantial non-U.S. EGU anthropogenic emissions of Hg. 

 

152 U.S. EPA-SAB, 2011. 
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The SAB commented that EPA’s approach to minimizing the 

potential for these biases to affect the results of the risk 

analysis appears to be sound and that additional criteria that 

could be applied are unlikely to substantially change the 

results. As a result, the EPA disagrees with the commenter that 

EPA’s screening process is inadequate. In addition, we conducted 

several sensitivity analyses to gauge the impact of excluding 

watersheds with the potential for non-EGU Hg emissions, and 

found that the results were robust to these exclusions.

In response to specific comments regarding the use of the 

Mercury Maps model, the EPA clarifies that the Hg Risk TSD did 

not directly use the Mercury Maps model. Instead, the EPA 

applied an assumption of linear proportionality between changes 

in Hg deposition and changes in MeHg concentrations in fish that 

is supported by the Mercury Maps modeling. By assuming steadystate conditions in apportioning fish tissue Hg levels and risk, 

the EPA does not attempt to project lag times. Recent research 

cited by the SAB153,154,155 identifies relatively rapid response of 

fish tissue Hg to changes in Hg loading, which suggests that 

fish tissue Hg levels could react more quickly to reductions in 

Hg deposition than previously thought. This finding reduces 

concern that fish tissue Hg levels could be linked to older 

 

153 Orihel et al., 2007.

154 Orihel et al., 2008.

155 Harris et al., 2007.
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patterns of Hg deposition and strengthens the approach used in 

the revised Hg Risk TSD. While fish tissue may respond rapidly 

to changes in Hg loading, this does not change the fact that 

previously emitted Hg from U.S. EGUs can be re-emitted and redeposited, and thus affect Hg concentration in fish.

2. Characterization of Subsistence Fishing Populations and 

Exposure Scenario

Comment: Several commenters stated that EPA provides no clear 

definition of subsistence, near subsistence, or high-end fish 

consumption, instead assuming that poverty is a direct 

indication of subsistence fishing and high-end fish consumption. 

One commenter stated no documentation exists to supports these 

assumptions. Another commenter stated that EPA’s definitions of

subsistence fishers in the Hg Risk TSD are not consistent with 

earlier EPA documents and are used inconsistently throughout the 

Hg Risk TSD. Several commenters stated that while subsistence 

fishing can be associated with poverty, poverty does not 

indicate subsistence fishing. One commenter stated that by 

including watersheds with as few as 25 members of individuals 

living in poverty, the EPA overstates risks.

One commenter stated that it is unclear what literature the 

Agency says “generally supports the plausibility of high-end 

subsistence-like fishing...to some extent across the watersheds”
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and stated that if other studies exist, the EPA should provide 

the values for comparison. 

One commenter stated that EPA combined two parameters with 

differing scales to establish the geographic unit used in the Hg 

Risk TSD risk assessment. The HUC watersheds are based on 

average about 35 square miles in size, while U.S. census tracts 

used to identify watersheds relevant for subpopulations of 

interest—cover a few tenths to hundreds of square miles. Several 

commenters stated that it is unclear how the analysis handled 

differences in geographic resolution between watersheds and 

census tracts were.

One commenter stated that the procedure for assigning 

census tracts could bias exposure outcomes. For example, the 

commenter stated that a single influential census tract in a 

watershed could drive risk, even if the watershed had only a 

minimal number of fish samples. The commenter stated that this 

possibility is a concern in urban areas, which account for the 

majority of census tracts, because these census tracts are more 

likely to be included in a risk analysis because they have more 

than 25 people living in poverty. The commenter stated that 

these census tracts may drive the extremes of the distribution 

without regard to the actual number of high-level, self-caught 

fish consumers within their boundaries. The commenter stated 
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that they could not assess the potential bias and noted that EPA 

did not test the bias by sensitivity analyses.

Several commenters stated that EPA was not clear whether 

the poverty criteria were applied in all scenarios or just for 

the high-end female fish consumer scenario. One commenter stated 

that EPA should apply the minimum 25 source population criteria 

only to populations of women of childbearing age. One commenter 

stated that EPA’s assumption would result in any densely 

populated urban census tract with a single fish tissue sample 

being assigned to a modeled watershed with populations 

potentially at-risk, regardless of the actual degree of 

recreational or subsistence fishing taking place there.

Response: The EPA agrees with the comments that subsistence fish 

consumption was not clearly defined, and we have provided a 

clearer definition in the revised Hg Risk TSD, however, this 

clarification does not result in any changes to the quantitative 

analysis. In the revised Hg Risk TSD, the EPA clarifies that 

“subsistence fishers” are defined as individuals who rely on 

noncommercial fish as a major source of protein.156 This 

definition is reflected in the range of fish consumption rates 

used in estimating risk. The likely presence of this type of 

 

156 U.S. EPA, U.S. Environmental Protection Agency. 2000. 

Guidance for Assessing Chemical Contaminant Data for Use in Fish 

Advisories, Volume 3: Overview of Risk Management. Office of 

Science and Technology, Office of Water, U.S. Environmental 

Protection Agency, Washington, D.C. EPA 823-B-00-007.
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subsistence fish consumer is supported by available peer 

reviewed literature (see Table 1-5 of the revised Hg Risk TSD). 

These studies clearly show that a subset of surveyed fishers 

consumes self-caught fish at the rates cited in the Hg Risk TSD. 

The SAB peer review concluded that the consumption rates and 

locations for fishing activity are supported by the data 

presented in the Hg Risk TSD, and are generally reasonable and 

appropriate given the available data.157

The EPA notes that there is some confusion in the comments 

related to the size of the watersheds modeled. Several 

commenters stated that HUC watersheds are 35 km on a side. The 

commenters appear to be referring to HUC8 classifications. The 

HUCs are defined for varying spatial resolutions. The geographic 

unit used as the basis for generating risk estimates is HUC12, 

which are watersheds about 10 km on a side, which is comparable 

with the size of the 12 km2 grid cells in CMAQ, which are 12km2. 

The EPA has also clarified that the specific unit of analysis 

for this assessment is at the watershed, not enumerated 

subpopulations. 

The EPA only used the U.S. Census tracts to determine 

whether there are populations in the vicinity of a given 

watershed, which could increase the potential for a category of 

subsistence fishers to be active at that watershed. In the 

 

157 U.S. EPA-SAB, 2011.
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revised Hg Risk TSD, the EPA modified the female subsistence 

scenario to apply equally to all watersheds with fish tissue Hg 

data based on the likelihood that these populations have the 

potential to fish at most watersheds. As described in the 

revised Hg Risk TSD, the EPA made this change in response to 

SAB’s concerns regarding the potential exclusion of watersheds 

with fewer than 25 individuals and regarding coverage for highend recreational fish consumption.158 Thus, concerns regarding 

the use of census data to select watersheds with the potential 

for subsistence fishing no longer apply to this scenario. 

However, for the remaining subsistence scenarios, the EPA 

continues to use U.S. Census tract-level data to evaluate the 

presence of a “source population” in the vicinity of the 

watershed being modeled for risk. In this context, the EPA uses 

the U.S. Census data to assess whether a socioeconomic status 

(SES)-differentiated group similar to the particular type of 

subsistence fisher being modeled (e.g., poor Hispanics) are 

located in the vicinity of the watershed. If a source population 

is nearby, then this increases the potential that subsistence 

fishing activity could occur for that population scenario.

 

158 This change led to a very small increase in the number of 

watersheds with populations potentially at-risk. In the Hg Risk 

TSD accompanying the proposed rule, approximately 4 percent of 

modeled watersheds were excluded based on the SES-based 

filtering criteria.
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The EPA continues to model risk for white and black 

subsistence fishers active in the southeast and for Hispanics 

assessed nationally. In this case, the EPA links poverty with 

subsistence fishing, as EPA only modeled locations with poor 

source populations. However, in modeling these three 

populations, the EPA asserts that the presence of a poor source 

population indicates the potential for subsistence fishing 

activity, rather the presence of such activity. The linkage 

between poverty and higher rates of subsistence fish consumption 

is supported by the Burger et al. study,159 which identified 

substantially higher consumption rates for poor individuals (see

Table 5 of the study). The EPA acknowledges that subsistence 

fishing activity by specific subpopulations might only be 

present across a subset of the watersheds EPA modeled for risk. 

However, given the stated goal of the analysis to determine the 

percent of watersheds where the potential exists for exposures 

to U.S. EGU-attributable Hg to represent a public health hazard, 

identifying a set of watersheds with the potential for the type 

of high fish consumption that leads to high Hg exposure is 

appropriate. The EPA notes that relatively few watersheds (less 

than 4 percent) have fish tissue Hg data, and, thus, can be 

included in the risk assessment. Consequently, while there is 

 

159 Burger, J., 2002. “Daily Consumption of Wild Fish and Game: 

Exposures of High End Recreationists,” International Journal of 

Environmental Research and Public Health, 12 (4), 343–54.
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the potential for including some watersheds in the analysis that 

may not have currently active subsistence fishing activity, it 

is likely that EPA excluded other watersheds from the analysis 

where this type of subsistence fishing activity occurs due to a 

lack of fish tissue Hg data.

While EPA agrees with the comment that it is likely that 

exposure to total MeHg through commercial fish consumption 

represents a more significant risk for the general population 

than consumption of freshwater fish obtained through self-caught 

fishing activity, exposure to total MeHg through self-caught 

fish consumption is the most significant risk for subsistence 

fishing populations and high-end recreational fishers. For the 

subset of these populations that focus their fishing activity in 

freshwater streams and lakes, it is also the case that they will 

experience a higher fraction of MeHg exposure attributable to 

U.S. EGU Hg emissions. As a result, the EPA focused the risk 

assessment on subsistence fishers active at inland freshwater 

watersheds because they are likely to experience the highest 

levels of individual risk as a result of exposure to U.S. EGUattributable Hg. 

3. Cooking Loss Adjustment Factor

Comment: Several commenters stated that EPA did not justify the 

selection of a cooking loss factor of 1.5 that, according to one 
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commenter, increases estimated intake by 50 percent, thus 

increasing the daily MeHg intake rate by a constant factor of 33 

percent and also increasing any resulting (HQ) risk estimate by 

a similar factor. Several commenters stated that the source of 

EPA’s selected loss factor160 reported a range of cooking losses 

from 1.1 to 6. Several commenters cite several studies that 

report no or highly variable changes in MeHg levels as a result 

of cooking fish.161,162,163,164,165 One commenter suggested that EPA’s 

cooking loss adjustment factor of 1.5 is at the high-end of the 

values supported by the literature. Another commenter stated 

that EPA has used other adjustment factors in previous 

documents, and that the adjustment factor should not be fixed 

 

160 Morgan, J.N., M.R. Berry, and R.L. Graves. 1997. “Effects of 

Commonly Used Cooking Practices on Total Mercury Concentration 

in Fish and Their Impact on Exposure Assessments.” Journal of 

Exposure Analysis and Environmental Epidemiology 7(1):119-133.

161 Armbruster G., Gerow K.G., Lisk D.J., 1988. “The Effects of 

Six Methods of Cooking on Residues of Mercury in Striped Bass,” 

Nutrition Reports International, 37, 123–126.

162 Gutenmann, W.H. and Lisk D.J., 1991. “Higher Average Mercury 

Concentration in Fish Fillets after Skinning and Fat Removal,” 

Journal of Food Safety, 11, 99–103. 

163 Farias L.A., Favaro, D.I., Santos J.O., Vasconcellos M.B., et 

al., 2010. “Cooking Process Evaluation on Mercury Content in 

Fish,” Acta Amazonia, 40 (4), 741–748.

164 Perelló G., Martí-Cid R., Llobet J.M., Domingo J.L., 2008. 

“Effects of Various Cooking Processes on the Concentrations of 

Arsenic, Cadmium, Mercury, and Lead in Foods,” Journal of 

Agricultural and Food Chemistry, 156 (22), 11262–11269. 

165 Torres-Escribano S., Ruiz A., Barrios L., Vélez D., Montoro 

R., 2011. “Influence of Mercury Bioaccessibility on Exposure 

Assessment Associated with Consumption of Cooked Predatory Fish 

in Spain,” Journal of the Science of Food and Agriculture, 91 

(6), 981–6.
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across different populations given potential differences in 

cooking practices. Several commenters noted that the cooking 

loss adjustment factor should only be applied to estimates of 

consumption rates for prepared fish, and that some sources of 

consumption rates are based on raw fish.

Response: The EPA disagrees with the commenters that the 

selection of the cooking loss factor of 1.5 is not justified by 

the literature. The EPA also disagrees with the comment that the 

cooking loss adjustment factor of 1.5 is at the high-end of the 

range of values in the literature. The EPA selected the Morgan 

study166 as the basis for the food preparation/cooking adjustment 

factor because it focused on the types of freshwater fish 

species representative of what might be consumed by subsistence 

fishing populations (i.e., walleye and lake trout). This study167

provides a range of adjustment factors for each fish type 

including 1.1 to 1.5 for walleye and 1.5 to 2.0 for lake trout. 

Given these two ranges, the EPA determined it to be reasonable 

to take an intermediate value between the two ranges (i.e., 

1.5), rather than focus on either the highest or lowest values, 

which is not the most conservative assumption that the EPA could 

have made. This study168 also explains that preparation/cooking 

of fish results in an increase in MeHg levels per unit fish 

 

166 Morgan et al., 1997.

167 Id.

168 Id.
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because Hg concentrates in the muscle, while preparation/cooking 

tends to reduce non-muscle elements (e.g., water, bone, fat). 

Regarding the alternative studies identified by the 

commenters, the EPA disagrees that these studies considered 

collectively contradict the cooking loss factor in the analysis. 

Specifically, the first study169 may have included measurement of 

non-fish components added to dishes (e.g., onions, heavy 

breading etc.), which could dilute the post-cooking Hg 

measurements and give the appearance of a cooking loss even as 

actual fish tissue Hg levels could have increased. In the second 

study,170 the fish species are saltwater and not freshwater, and 

the authors note that the reduction of water and fat could 

increase in the Hg concentration without changing absolute 

content. The third study focused on measurement of bioaccessible 

Hg in raw and cooked fish.171 However, available information 

currently allows us to specify the risk model in terms of total 

Hg intake, not bioaccessible Hg, thus, this article is 

potentially informative for guiding future research and methods 

development, not the current risk assessment. The fourth study172

found a modest but statistically insignificant increase in Hg 

levels for most of the cooking methods assessed, which is 

 

169 Farias et al., 2002. 

170 Perelló et al., 2008. 

171 Torres-Escribano et al., 2011

172 Armbruster et al., 1988.
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directionally consistent with EPA’s cooking loss adjustment. The 

fifth study173 only addressed the issue qualitatively, thus 

cannot be used for the cooking loss factor. When considered 

collectively, the EPA disagrees that the additional studies 

identified by the commenter contradict the cooking loss factor 

used in the risk assessment and maintains that the Morgan 

study174 remains the most applicable for characterizing 

cooking/preparation effects on Hg concentrations in fish.

The EPA agrees that application of the cooking loss 

adjustment factor is appropriate if the fish consumption rates 

are for as cooked or as consumed and not for raw fish. Careful 

review of the three studies used in the risk assessment to 

identify subsistence fisher consumption rates suggests that all 

three represent annual-average daily intakes (g/day) of as 

consumed or as cooked fish. One study stated that they used 

models of portion or meal size servings (the size of the serving 

the respondent regularly eats).175 Therefore, the EPA interprets 

the fish consumption rates provided in this study176 as 

representing as cooked/prepared and not for raw fish and for 

that reason, application of a preparation/ cooking adjustment 

 

173 Gutenmann et al., 1991.

174 Morgan et al., 1997. 

175 Burger et al., 2002.

176 Id.
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factor is required. Another study177 used different sized models 

of cooked fish filets and therefore these consumption rates are 

also interpreted as represented as cooked/prepared and not raw 

fish. One study178,179 queried survey responders for meal portion 

or serving size and therefore, the consumption rates do 

represent as cooked/prepared. Because all three studies provide 

consumption rates based on as cooked/prepared or as consumed, it 

is appropriate to apply the cooking loss adjustment factor in 

modeling exposure.

4. Fish Consumption Rates and Fish Tissue Hg Characterization

Comment: One commenter stated that in the past the Agency has 

recommended various default consumption rates (in the general 

range of 130 to <150 g/day) to provide default intakes for 

subsistence fishers under the Risk Assessment Guidance for 

Superfund (RAGS) or the Fish Advisory Guidance.

180,181 The 

commenter stated that these default consumption rates are 

derived from various studies and generally are based on 90th or 

 

177 Shilling, Fraser, Aubrey White, Lucas Lippert, Mark Lubell 

(2010). Contaminated fish consumption in California’s Central 

Valley Delta. Environmental Research 110, p. 334-344.

178 Dellinger JA. 2004. “Exposure assessment and initial 

intervention regarding fish consumption of tribal members of the 

Upper Great Lakes Region in the United States.” Environ Res

95:325–340.

179 Personal communication, Dr. Dellinger, September 27, 2011

180 U.S. EPA. 1991. Risk Assessment Guidance for Superfund 

(RAGS). Part C 1991 EPA/9285.7-01C. October.

181 U.S. EPA. 2000. National Guidance: Guidance for Assessing 

Chemical Contaminant Data for Use in Fish Advisories, Volume 2. 

EPA 823-B-00-008, November.
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99th percentile distribution estimates. Another commenter stated 

that EPA’s use of the 99th percentile fish consumption for its 

risk analysis is inconsistent with the Agency’s risk assessment 

guidelines, which recommend evaluating a reasonable maximum 

exposure (“RME”) scenario,182 which equates to about a 95th

percentile fish consumption value. The same commenter stated 

that EPA applied the 99th percentile to a “small survey of 149 

South Carolina female anglers” to calculate an ingestion rate 

of 373 grams per day (g/day). The commenter stated that if the 

95th percentile is used the ingestion rate would be 173 g/day and 

if the default ingestion rate for determining ambient water 

standards is used the ingestion rate would be 142 g/day.

Several commenters stated that EPA based its fish 

consumption rates used in the risk analysis on a limited number 

of studies and that those studies are poorly documented. 

Another commenter stated that EPA should summarize 

available supporting studies by basic study content, 

characteristics, design, size, demographics, dietary recall 

period, and fish intake rates by demographic variables. 

According to the commenter, this summary would support the 

scientific validity of the assessment and better illustrate the 

potential variability and uncertainty involved in extrapolating 

 

182 U.S. EPA. 1989. Risk Assessment Guidance for Superfund 

(RAGS). EPA/540/1-89/002. December.
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data from small populations to the national-scale. The commenter 

also noted that the three studies actually used to provide 

subsistence population estimates, which were extrapolated to the 

national-scale, included a limited number of individuals living 

in diverse and localized areas.

One commenter stated that the assumption with the greatest 

impact on risk is the fish consumption rate. That same commenter 

stated that using 99th percentile ingestion rate dramatically 

increases HQ and IQ loss compared to the 50th percentile 

ingestion rate. The commenter stated that when an estimate of 

the 95th percentile ingestion rate of the 15 to 44 year old 

female population is considered, the HQ is a tenth of the value 

computed with the 99th percentile high-end female fisher.

One commenter stated that EPA provides broad summary 

statistics of its fish tissue data in Table 5-2 of the 

Regulatory Impact Analysis (RIA), but the summary does not allow 

an assessment of the representativeness and robustness of the 

underlying data for the risk assessment, especially at the tails 

of the distribution. The commenter stated that the table does 

not include a median statistic and does not provide any 

information on the number of lakes and river segments in each 

watershed. According to the commenter, an analysis of EPA’s 

database by the SAB indicated that 60 percent of the watersheds 
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with fish Hg data from rivers have risks calculated based upon a 

sample size of one or two fish. The commenter stated that it is 

not reasonable to base a significant policy and regulation 

decision on watersheds where exposure is based on a single fish 

sample in a single water body within it.

Several commenters criticized EPA’s use of the 75th

percentile fish tissue MeHg level in a watershed. One commenter 

stated that EPA provided no rationale for its decision to choose 

the highest of the 75th percentile for fish Hg levels among 

rivers and lakes within the HUC. Several commenters stated that 

subsistence fishers are less likely to target larger fish 

relative to recreational fishers. Several commenters suggested 

that EPA include a sensitivity analysis using the mean or median 

fish MeHg level in a watershed. One commenter also stated that 

EPA arbitrarily inflated the risk estimates by assuming 

consumption of only fish greater than 7 inches and choosing the 

largest of the 75th percentile of fish Hg levels from these 

larger fish (i.e., larger than 7 inches) for rivers and lakes. 

That same commenter suggested using the median of all size fish, 

not just those over 7 inches. 

One commenter stated that EPA should quantify adverse 

effects from the ingestion of MeHg in seafood in addition to 

ingestion of MeHg from self-caught freshwater fish. According to 
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the commenter, recent studies demonstrate that were EPA to take 

into account consumption of seafood, MeHg consumption in the 

U.S. is of even greater concern.

Response: The EPA acknowledges that the focus of the Hg Risk TSD 

is characterizing risk for the groups likely to experience the 

greatest U.S. EGU-attributable Hg risk, which are subsistence 

fishing populations active at inland freshwater lakes and 

rivers. Specifically, within that subsistence fishing 

population, the EPA is interested in those individuals who are 

most at-risk, which includes those who consume the most fish. 

For that reason, the EPA considered a range of high-end fish 

consumption rates including the 99th percentile representing the 

most highly-exposed individuals. In responding to the SAB peer 

review, the EPA clarified this focus in the introduction to the 

revised Hg Risk TSD and changed the full title to revised 

Technical Support Document: National-Scale Assessment of Mercury 

Risk to Populations with High Consumption of Self-caught 

Freshwater Fish. 

The EPA agrees that the fish consumption rate is an 

important factor in calculating risk from exposure to MeHg in 

fish. The EPA acknowledges that the distribution of fish 

consumption rates is positively skewed, which means that at 

higher percentiles (e.g., 90th, 95th, and 99th) there is a 
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substantial increase in ingestion rates relative to the mean or 

median. The revised Hg Risk TSD includes a reasonableness check 

on the amount of fish consumed (as a daily value) reflected in 

the different rates. While the 99th percentile consumption rates 

for the subsistence female fisher (373 g/day) is substantially 

higher than the 90th or 95th percentile values (123 and 173 g/day 

respectively), the 99th percentile value translates into a 13-

ounce meal. While this represents a large serving, it is still 

reasonable if representing an individual who receives all of 

their meat protein from self-caught fishing, and the 13 ounces 

per day do not have to be eaten all at one meal. The higher 

consumption rates (i.e., greater than 250 g/day) are supported 

by all three studies used in the risk assessment, and therefore, 

there is support across studies near the upper bound of likely 

consumption rates in this range. The EPA acknowledges 

uncertainty associated with estimating high-end percentile 

values in these studies due to relatively low sample sizes for 

some population groups. However, even if a few individuals 

reported these high self-caught fish consumption rates, making 

it difficult to characterize the population percentiles they 

represent, the values still suggest that these levels of high 

fish consumption exist among surveyed individuals. To determine 

whether a public health hazard could exist, the EPA asserts that 
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it is reasonable to include these consumption rates as 

representative of the most at-risk populations. In these cases, 

however, the EPA acknowledges that it is important to highlight 

uncertainty associated with characterizing the specific 

population percentile that these ingestion rates represent, and 

EPA has done so in the revised Hg Risk TSD.

The EPA disagrees with the comment that high consumption 

rates are poorly documented. Evidence of these high fish 

consuming populations can be found in surveys183 and specialized 

studies.184,185,186,187,188 Several studies identified additional 

fishing populations with subsistence or near subsistence 

consumption rates, including urban fishing populations 

 

183 Burger et al., 2002.

184 Burger, J., K. Pflugh, L. Lurig, L. Von Hagen, and S. Von 

Hagen. 1999a. “Fishing in Urban New Jersey: Ethnicity Affects 

Information Sources, Perception, and Compliance.” Risk Analysis

19(2): 217-229.

185 Burger, J., Stephens, W. L., Boring, C. S., Kuklinski, M., 

Gibbons, J. W., Gochfeld M. 1999b. “Factors in Exposure 

Assessment: Ethnic and Socioeconomic Differences in Fishing and 

Soncumption of Fish Caught along the Savannah River.” Risk 

Analysis, Vol. 19, No. 3, p. 427.

186 California Environmental Protection Agency (CalEPA). 1997. 

Chemicals in Fish Report No. 1: Consumption of Fish and 

Shellfish in California and the United States Final Draft 

Report. Pesticide and Environmental Toxicology Section, Office 

of Environmental Health Hazard Assessment, July.

187 Tai, S. 1999. “Environmental Hazards and the Richmond Laotian 

American Community: A Case Study in Environmental Justice.” 

Asian Law Journal 6: 189.

188 Corburn, J. 2002. “Combining community-based research and 

local knowledge to confront asthma and subsistence-fishing 

hazards in Greenpoint/Williamsburg, Brooklyn, New York.” 

Environmental Health Perspectives 110(2).
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(including low-income populations),189,190,191 Laotian 

communities,192 and Hispanics. The EPA participated in 1999 in a 

project investigating exposures of poor, minority communities in 

New York City to a number of contaminants including Hg, which 

found these populations can have very high fish consumption 

rates.193 The SAB concluded that the consumption rates and 

locations for fishing activity are supported by the data 

presented in the Hg Risk TSD, and are generally reasonable and 

appropriate given the available data.194

The EPA agrees that the Hg Risk TSD would be improved by 

clarifying that the literature review focused on identifying 

studies that characterize subsistence fish consumption for 

groups active at freshwater locations within the U.S., and EPA 

has revised the Hg Risk TSD accordingly. In the Hg Risk TSD, the 

EPA summarized important study attributes for the source studies 

used to obtain fish consumption rates. This information was 

provided in Table C-1 in an appendix. To improve clarity, the 

EPA moved the summary table to the main body in the revised Hg 

Risk TSD. In identifying these studies, the EPA focused on

surveys for subsistence fishers that were applicable at the 

 

189 Burger et al., 1999a.

190 Burger et al., 1999b.

191 CalEPA, 1997.

192 Tai, 1999..

193 Corburn, 2002.

194 U.S. EPA-SAB, 2011.
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broader regional or national level. In the Hg Risk TSD, the EPA 

acknowledged the smaller sample sizes for some of the 

subsistence fisher groups, and in several cases the EPA did not 

use the 99th percentile consumption rates because the sample 

sizes were too low to support this level of resolution. This 

decision did not affect EPA’s finding of a hazard to public 

health, which is based on the results for the female subsistence 

fishing population, which has an estimate of the 99th percentile 

consumption rate that is supported by an adequate sample size.

The EPA disagrees with the comment that it did not provide 

a rationale for choosing the 75th percentile fish tissue 

concentration across lakes and rivers in a watershed. However, 

the EPA modified the methodology based on evaluation of the 

number of samples within each watershed (responding to a 

recommendation from the SAB). In the revised methodology, the 

EPA computes the 75th percentile value at each sampling site 

within a watershed. The EPA then computed the average of the 

site-specific 75th percentile fish tissue Hg values within a 

given watershed. This approach does not differentiate between 

rivers and lakes and reflects an improved treatment of behavior, 

allowing for fishers to choose among multiple fishing sites 

within a watershed. 
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The EPA generally agrees with the comment that some 

fraction of subsistence fishers likely consume fish without 

consideration for size (given dietary necessity), however, the 

EPA considers it reasonable to assume that a subset of 

subsistence fishers could target larger fish in order to 

maximize the potential consumption per unit of fishing effort. 

The EPA uses this subset of subsistence fishers targeting larger 

fish, which is represented by the 75th percentile fish tissue 

value, in the risk assessment. In addition, including the female 

subsistence fishing population in the analysis also provides 

coverage for high-end recreational anglers who target larger 

freshwater fish. The SAB commented that: “Using the 75th

percentile of fish tissue values as a reflection of consumption 

of larger, but not the largest, fish among sport and subsistence 

fishers is a reasonable approach and is consistent with 

published and unpublished data on predominant types of fish 

consumed.”

195 The SAB suggested that EPA include a sensitivity 

analysis based on use of the median value, and EPA has done so 

in the revised Hg Risk TSD. This sensitivity analysis showed 

that using the median estimates had only a small impact on the 

number and percent of modeled watersheds with populations 

potentially at-risk from U.S. EGU-attributable MeHg exposures.

In the revised Hg Risk TSD, the EPA clarified that the 7-inch 

 

195 U.S. EPA-SAB, 2011.
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cutoff represents a minimum size limit for a number of key 

edible freshwater fish species established at the State-level. 

For example, Pennsylvania establishes 7 inches as the minimum 

size limit for both trout and salmon (other edible fish species 

such as bass, walleye and northern pike have higher minimum size 

limits).196

The EPA disagrees with the comment that it is not 

reasonable to use watersheds where only a single fish sample is 

available. Although it is generally preferred to have multiple 

samples, the SAB noted that using a single sample is likely to 

underestimate the 75th percentile fish MeHg concentration and is, 

therefore, likely to underestimate the risk estimates for those 

watersheds. The SAB suggested that EPA conduct additional 

analyses of the fish tissue MeHg data, which EPA has done and 

included in the revised Hg Risk TSD. The revised Hg Risk TSD 

includes information on the number of watersheds modeled in the 

risk assessment with various fish tissue Hg samples sizes (e.g., 

1, 2, 3-5, 6-10 and >10 measurements).

5. Reference Dose (RfD) for MeHg and Hg Health Effects Studies

Comment: Several commenters stated that EPA’s RfD197 is based on 

sound science, which was supported by the findings of the NAS 

 

196 Pennsylvania Fish and Boat Commission. 2011. Summary Book: 

2011 Pennsylvania Fishing Laws & Regulations available at: 

http://fishandboat.com/fishpub/summary/inland.html.

197 U.S. Environmental Protection Agency – Integrated Risk 
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Study,198 and that EPA appropriately applied the RfD in the Hg 

risk assessment. The commenters also stated that recent studies 

find clear associations between maternal blood Hg levels and 

delayed child development and cardiovascular effects, as well as 

potential for effects due to exposure to pollutant mixtures 

including lead. 

However, many commenters expressed concerns regarding EPA’s 

use of the MeHg RfD as a benchmark for health risk. Several 

commenters raised concerns claiming that EPA has not 

incorporated the best available Hg toxicological data into the 

RfD, which results in a flawed analysis and an overestimate of 

the impact of Hg emissions on human health.

Several commenters stated that, when deriving the RfD, the 

EPA relied on the flawed Faroe Islands’ children study and 

ignored the Seychelles Islands study,199 which did not confirm 

any harm on children due to MeHg exposure. According to the 

commenters, application of the Faroe Island study is suspect 

because (1) the raw data from the study have never been made 

available for independent analysis and scrutiny, (2) there is 

potential for confounding by polychlorinated biphenyls (PCBs) 

 

Information System (U.S. EPA-IRIS). 2001. Methylmercury (MeHg) 

(CASRN 22967-92-6). Available at 

http://www.epa.gov/iris/subst/0073.htm

198 NAS, 2000.

199 Budtz-Jorgensen E, Debes F, Weihe P, Grandjean P. 2005. 

“Adverse Mercury Effects in 7-Year-Old Children Expressed as 

Loss in “IQ”.” EPA-HQ-OAR-2002-0056-6046.
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and lead, (3) population exposure to MeHg was through 

consumption of highly contaminated pilot whale meats and 

blubbers, and (4) exposure levels in the U.S. remain lower than 

those observed in the primary study. One commenter also notes 

that (1) Seychelles Islanders consume far more fish than 

Americans do; (2) the amount of MeHg in the U.S. population is 

much lower than the Seychelles islanders; and (3) all ocean fish 

contain about the same amount of MeHg, so MeHg intake per fish 

meal is similar between Americans and Seychelles Islanders. 

However, another commenter stated that industry arguments 

against using the Faroe Islands study fail to acknowledge that 

the study results were consistent with studies in the Seychelles 

Islands, New Zealand,200 and Poland.201

One commenter criticized EPA for using a linear doseresponse model for the RfD-based HQ metric and the IQ metric. 

Another commenter stated that the RfD assumes a threshold dose 

below which an appreciable risk of adverse effects is unlikely, 

and NAS did not evaluate whether MeHg exposure data were better 

 

200 Kjellstrom, T; Kennedy, P; Wallis, S; et al. 1986. Physical 

and mental development of children with prenatal exposure to 

mercury from fish. Stage 1: Preliminary test at age 4. Natl Swed 

Environ Protec Bd, Rpt 3080 (Solna, Sweden).

201 Wieslaw Jedrychowski et al. 2006. “Effects of Prenatal 

Exposure to Mercury on Cognitive and Psychomotor Function in 

One-Year-Old Infants: Epidemiologic Cohort Study in Poland,” 16 

Annals of Epidemiology 439.
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fit by a linear or non-linear model or by a threshold or nonthreshold model. 

Several commenters stated that EPA’s MeHg RfD is more 

conservative than “safe” levels determined by other federal 

agencies and claim that EPA assigned unusually high uncertainty 

factors. Several commenters stated that EPA’s use of the 1999 

National Health and Nutrition Examination Survey (NHANES) blood 

Hg levels show a downward trend since 1999, and the levels have 

been below the RfD since 2001. 

One commenter stated that a study by Texas Department of 

State Health Services (DSHS, 2004)202 determined that among 

subsistence fishers who eat fish from Caddo Lake with elevated 

MeHg, women of child-bearing years did not have blood Hg levels 

greater than the RfD. Thus, according to the commenter, the 

connection between MeHg in fish and adverse health effects in 

the U.S. is not fully understood and could involve other 

factors, including the protective effects of fatty acids and 

selenium in fish, which EPA did not taken into account. 

Two commenters claim that EPA uses the RfD as if it were an 

absolute threshold for health risk in the risk assessment even 

 

202 DSHS. 2005. Health Consultation: Mercury Exposure 

Investigation Caddo Lake Area-Harrison County Texas. Agency for 

Toxic Substances and Disease Registry. 

http://www.tceq.state.tx.us/assets/public/comm_exec/pubs/sfr/085

.pdf
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though the RfD methodology is a screening tool for deciding when 

risks clearly do not exist. 

Several commenters recommended adding qualitative 

discussions to the Hg Risk TSD regarding several aspects of 

uncertainty, including uncertainty in the RfD, uncertainty in 

extrapolating a dose-response relationship between MeHg exposure 

and change in IQ, uncertainty in extrapolating the dose-response 

relationship from marine fish and marine mammals to freshwater 

fish, and uncertainty due to potential confounding by PCBs in 

marine species.

Several commenters raised concerns regarding the 

relationship between MeHg exposure and IQ loss. Two commenters 

stated that changes in IQ are not a well-defined health 

consequence of MeHg exposure. One commenter stated that the SAB 

had reservations about EPA’s use of IQ loss. Two commenters 

questioned whether IQ impacts would even occur because in Japan 

and Korea, where the maternal blood Hg levels are higher than in 

the U.S., there is no evidence of adverse effects. Another 

commenter cited a study203 that found verbal IQ scores for 

children from mothers with no seafood intake were 50 percent 

more likely to be in the lowest quartile. One commenter 

 

203 Hibbeln JR, Davis JM, Steer C, Emmett P, Rogers I, Williams 

C, et al. 2007. “Maternal seafood consumption in pregnancy and 

neurodevelopmental outcomes in childhood (ALSPAC study): an 

observational cohort study. “ Lancet 369:
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questions using an IQ risk metric threshold of >1 or >2 points 

because variation in IQ measures and the intra-individual 

variation in IQ are higher than the threshold. 

Several commenters question the relationship between 

cardiovascular effects and MeHg exposure. Two commenters cited 

studies examining the relationship between MeHg exposure and 

cardiovascular effects,204,205,206,207,208,209 but concluded that it 

seems premature to use these studies to establish a doseresponse relationship. 

Several commenters assert that the risks from eating 

seafood are low relative to the benefits, that fish advisories 

can limit the beneficial aspects of fish consumption, and that 

 

204 Roman HA, Walsh TL, Coull BA, Dewailly É, Guallar E, Hattis 

D, et al. 2011. Evaluation of the Cardiovascular Effects of 

Methylmercury Exposures: Current Evidence Supports Development 

of a Dose–Response Function for Regulatory Benefits Analysis. 

Environ Health Perspect 119:607-614.

205 Guallar E, Sanz-Gallardo MI, van’t Veer P, et al. 2002. 

“Mercury, fish oils, and the risk of myocardial infarction.” N 

Engl J Med.;347:1747.

206 Virtanen JK, Voutilainen S, Rissanen TH, et al. 2005. 

“Mercury, fish oils, and risk of acute coronary events and 

cardiovascular disease, coronary heart disease, and all-cause 

mortality in men in eastern Finland.” Arterioscler Thromb Vasc 

Biol. 2005;25:228.

207 Yoshizawa, Rimm, Morris, Spate, Hsieh, Spiegelman, Stampfer, 

Willett. “Mercury and the Risk of Coronary Heart Disease in 

Men,” N Engl J Med 2002; 347:1755-1760.

208 Hallgren CG, Hallmans G, Jansson JH, et al. 2001. Markers of 

high fish intake are associated with decreased risk of a first 

myocardial infarction. Br J Nutr: 86:397.

209 Mozaffarian, Dariush. 2011. “Mercury Exposure and Risk of 

Cardiovascular Disease in Two U.S. Cohorts,” N Engl J Med 364: 

1116-1125.
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fish advisories are often unsuccessful in changing behavior.210,211

One commenter noted the important protective role of dietary 

selenium against MeHg toxicity because the binding affinity of 

Hg to Se is much higher than binding to sulfur.

Response: The EPA agrees with commenters that state the MeHg RfD 

is the appropriate health value for determining elevated risks 

from MeHg exposure and disagrees with commenters that state 

otherwise. At this time, the EPA is neither reviewing nor 

revising its 2001 RfD for MeHg. The 2001 RfD for MeHg is EPA’s 

current peer-reviewed RfD, which is the value EPA uses in all 

its risk assessments. The EPA’s RfD is based on multiple 

benchmark doses, and RfDs were calculated on various endpoints 

using the three extant large studies of childhood effects of in

utero exposure: Faroe Islands, New Zealand, and an integrative 

measure including data from Seychelles. The EPA did not choose 

to base the MeHg RfD solely on results from the Seychelles 

Islands, as both the NAS212 and an independent scientific review 

panel convened as part of the IRIS process213 advised strongly 

against using results from a study that at the time had not 

shown an association between MeHg exposure and adverse effects. 

 

210 Hibbeln et al. 2007.

211 Mozaffarian, et al., 2011

212 NAS, 2000.

213 U.S. EPA. 2001b. Responses to Comments of the Peer Review 

Panel and Public Comments on Methylmercury. Available on the 

Internet at http://www.epa.gov/iris/supdocs/methpr.pdf
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Further, the EPA disagrees with comments stating that EPA based 

the MeHg RfD solely on results from the Faroe Islands population 

and disagrees that the information underlying the RfD is “poorly 

explained”. The EPA has provided detailed documentation for the 

choices underlying calculation of the RfD.214,215,216 To correct a 

misunderstanding by the commenter, the data underlying the Faroe 

Islands study have been previously published in the peer 

reviewed literature.

The EPA disagrees that it did not incorporate the latest Hg 

data to support the appropriate and necessary finding. It is the 

policy of EPA to use the most current peer reviewed, publicly 

available data and methodologies in its risk assessments. 

However, the EPA noted in the preamble to the proposed rule that 

“data published since 2001 are generally consistent with those 

of the earlier studies that were the basis of the RfD, 

demonstrating persistent effects in the Faroe Island cohort, and 

in some cases associations of effects with lower MeHg exposure 

concentrations than in the Faroe Islands. These new studies 

provide additional confidence that exposures above the RfD are 

 

214 U.S. EPA, 2001a. Water Quality Criterion for the Protection 

of the Human Health: MethylmercuryEPA-823-T-01-001, available at 

http://water.epa.gov/scitech/swguidance/standards/criteria/aqlif

e/pollutants/methylmercury/index.cfm

215 U.S. EPA-IRIS, 2001. 

216 Rice D, Schoeny R, Mahaffey K. 2003. “Methods and Rationale 

for Derivation of a Reference Dose for Methylmercury by the U.S. 

EPA.” Risk Analysis 23(1)107-115.
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contributing to risk of adverse effects, and that reductions in 

exposures above the RfD can lead to incremental reductions in 

risk.” However, the EPA has not completed a comprehensive review 

of the new literature, and as such, it would be premature to 

draw conclusions about the overall implications for the RfD. 

The EPA agrees that EPA’s RfD is not the same as the levels 

used by other federal agencies. In their advice to the EPA on 

the appropriate bases for a MeHg RfD, NAS specifically 

recommended that EPA use neither the study nor the uncertainty 

factor employed by the Agency for Toxic Substances Disease 

Registry (ATSDR) in the calculation of the minimal risk level.217

The EPA disagrees that the uncertainty factor is “unusually 

high”. The uncertainty factor used in calculation of EPA’s peerreviewed RfD is small (10 fold); half of this factor is to 

account for measured variability in human pharmacokinetics, 

which is based on advice of the NAS218 and an independent panel 

of scientific peer reviewers convened as part of the IRIS 

process219. 

The IRIS makes this statement regarding a threshold for 

MeHg, “It is also important to note that no evidence of a 

threshold arose for methylmercury-related neurotoxicity within 

the range of exposures in the Faroe Islands study. This lack [of 

 

217 NAS, 2000.

218 Id.

219 U.S. EPA, 2001b.
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a threshold] is indicated by the fact that, of the K power 

models, K = 1 provided a better fit for the endpoint models than 

did higher values of K.”

220

The EPA disagrees that it is using the MeHg RfD as an 

absolute bright line for health effects in the risk assessment. 

As stated in the preamble to this proposed rule, the RfD is an 

estimate of a daily exposure to the human population that is 

likely to be without an appreciable risk of deleterious effects 

during a lifetime. The EPA also stated that no RfD defines an 

exposure level corresponding to zero risk. Because mercury is a 

cumulative neurotoxin, it is important to distinguish health 

effects from public health hazard. Within the context of the 

appropriate and necessary finding, we interpret a public health 

hazard as risk, rather than certain occurrence of health 

effects. 

The EPA disagrees that exposure levels in the U.S. are 

lower than those in the Faroe Islands study. Exposure to MeHg in 

the U.S. has been reported at the same levels as those published 

in the Faroe Islands.221 One study notes that in the NHANES data 

(1999 to 2004), the highest five percent of women’s blood Hg 

 

220 U.S. EPA-IRIS, 2001.

221 Schober Susan E, Sinks Thomas H, Jones Robert L, Bolger P 

Michael, McDowell Margaret, Osterloh John, Garrett E Spencer, 

Canady Richard A, Dillon Charles F, Sun Yu, Joseph Catherine B, 

Mahaffey Kathryn R. Blood mercury levels in U.S. children and 

women of childbearing age, 1999-2000. JAMA. 2003 Apr 2; 

289(13):1667–1674.
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exceeded 8.2 microgram per liter (μg/L) in the Northeast U.S. 

and 7.2 μg/L in coastal areas.222 Higher levels have been 

reported among subjects known to consume fish. For example, one 

study reported mean blood Hg for adult women to be 15 μg/L; 

range for men and women was 2 to 89.5 μg/L.223 Note that some 

publications have reported Hg effects in U.S. populations at or 

below the current U.S. RfD.224,225 Also, the EPA disagrees with the 

commenter stating all ocean fish throughout the world contain 

about the same amount of MeHg. Marine fish in commerce differ 

widely in Hg concentration by species, and fish within the same 

species but caught at different locations have variable amounts 

of Hg in their tissues.226,227

 

222 Mahaffey, K.R., R.P. Clickner and R.A. Jeffries. 2009. Adult 

Women’s Blood Mercury Concentrations Vary Regionally in the 

U.S.: Association with Patterns of Fish Consumption (NHANES 

1999–2004). Environ. Health Perspect., 117: 47-53.

223 Hightower Jane M, Moore Dan. Mercury levels in high-end 

consumers of fish. Environ Health Perspect. 2003 Apr;111(4):604–

608. 

224 Oken, E., Radesky, J.S., Wright, R.O., Bellinger, D.C., 

Amarasiriwardena, C.J., Kleinman, K.P., Hu, H., Gillman, M.W. 

2008. Maternal fish Intake during Pregnancy, Blood Mercury 

Levels, and Child Cognition at Age 3 Years in a U.S. Cohort. 

American Journal of Epidemiology, 167(10), 1,171-1,181.

225 Lederman, Sally Ann Robert L. Jones, Kathleen L. Caldwell, 

Virginia Rauh, Stephen E. Sheets, Deliang Tang, Sheila 

Viswanathan, Mark Becker, Janet L. Stein, Richard Y. Wang, and 

Frederica P. Perera. 2008. Relation between Cord Blood Mercury 

Levels and Early Child Development in a World Trade Center

Cohort. Environmental Health Perspectives 118(8) 1085 -1091.

226 Hisamichi Y, Haraguchi K, Endo T. 2010. “Levels of mercury 

and organochlorine compounds and stable isotope ratios in three 

tuna species taken from different regions of Japan.” Environ Sci 

Technol 44(15):5971-8.
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The EPA disagrees that there is a statistically discernible 

downward trend in the NHANES data on blood Hg. The EPA is 

unaware that a formal statistical analysis for temporal trends 

has been completed for NHANES data on blood Hg levels for the 

period 1999 to 2008. Mahaffey et al., evaluating NHANES data 

collected 1999 to 2004 for women at child-bearing age, could 

“not support the conclusion that there was a general downward 

trend in blood Hg concentrations over the 6-year study 

period.”

228 However, the same publication noted that “there was a 

decline in the upper percentiles reflecting the most highly 

exposed women” having blood Hg concentration greater than 

established levels of concern. Visual observations of the data 

show a slight decrease in Hg blood level concentrations from 

1999-2008 at the geometric mean, but this decrease may not be 

statistically significant. The EPA remains concerned that 

substantial numbers of women of childbearing age in the U.S. may 

have blood Hg levels that are equivalent to exposures at or 

above the RfD. While mean and 95th percentiles from recent NHANES 

data are below the blood Hg concentration equivalent to the RfD, 

blood levels for some portions of the population (high consumers 

 

227 Sunderland EM. 2007. “Mercury exposure from domestic and 

imported estuarine and marine fish in the U.S. seafood market.” 

Environ Health Perspect. 115(2):235-42. Epub 2006 Nov 20.

228 Mahaffey, K.R., R.P. Clickner and R.A. Jeffries. 2009. Adult 

Women’s Blood Mercury Concentrations Vary Regionally in the 

U.S.: Association with Patterns of Fish Consumption (NHANES 

1999–2004). Environ. Health Perspect., 117: 47-53.
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of fish, for example) show exposures above this level. One study

estimated very high blood Hg levels at the 99th percentile for 

females of child-bearing age.229 Other published studies have 

shown that various population groups can have high blood Hg 

levels.230,231,232,233,234 For example, one study found that 83 percent 

of the NHANES Asian population exceeded the RfD-equivalent blood 

mercury level.235

The EPA disagrees with the commenter regarding confounding 

by PCBs and lead. Exposure to MeHg in the Faroe Islands was 

largely from consumption of pilot whale meat; exposure to PCBs 

was found in the portion of the population who also consume 

whale blubber. Numerous analyses have shown neurobehavioral 

effects of PCBs; however, the effects of MeHg and PCB in the 

Faroe Islands study are separable.236 The EPA also documented the 

independence of PCB and MeHg effects in the Faroe Islands 

 

229 Tran, N. L., L. Barraj, et al. 2004. “Combining food 

frequency and survey data to quantify long-term dietary 

exposure: a methyl mercury case study.” Risk Anal 24(1): 19-30.

230 Id.

231 Miranda, M. L., S. Edwards, et al. 2011. “Mercury levels in 

an urban pregnant population in Durham County, North Carolina.” 

Int J Environ Res Public Health 8(3): 698-712.

232 Hightower and Moore, 2003.

233 Hightower, J. M., A. O’Hare, et al. (2006). “Blood mercury 

reporting in NHANES: identifying Asian, Pacific Islander, Native 

American, and multiracial groups.” Environ Health Perspect 

114(2): 173-175.

234 McKelvey, W., R. C. Gwynn, et al. 2007. “A biomonitoring 

study of lead, cadmium, and mercury in the blood of New York 

city adults.” Environ Health Perspect 115(10): 1435-1441.

235 Hightower et al., 2006.

236 NAS, 2000.
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population.237 The National Institute of Environmental Health 

Sciences (NIEHS) concluded that both PCB and Hg had adverse 

effects. 238 The NAS concluded that there was no empirical 

evidence or theoretical mechanism to support the opinion that in 

utero Faroese exposure to PCBs exacerbated the reported MeHg 

effect.239 A second set of analyses found that the effect of 

prenatal PCB exposure was reduced when the data were sorted into 

tertiles by cord PCB concentrations.240 These analyses support a 

conclusion that there are measurable effects of MeHg exposure in 

the Faroese children that are not attributable to PCB toxicity.

We also note that there was no report of lead exposure in the 

Faroe Islands population.

The EPA disagrees with the commenter’s assertion that the 

connection between MeHg in fish and observed health effects is 

not understood due to evidence from the cited Texas study.241

This is an exposure study rather than a study on measures of 

neurobehavioral or any other health endpoint. TCEQ noted that 

 

237 U.S. EPA, 2001a.

238 National Institute of Environmental Health Sciences (NIEHS). 

1998. Scientific issues relevant to assessment of health effects 

from exposure to methylmercury. Workshop organized by Committee 

on Environmental and Natural Resources (CENR) Office of Science 

and Technology Policy (OSTP), The White House, November 18-20, 

1998, Raleigh, NC.

239 NAS, 2000.

240 Budtz-Jørgensen, E., N. Keiding, and P. Grandjean. 1999. 

Benchmark modeling of the Faroese methylmercury data. Final 

Report to U.S. EPA.

241 DSHA, 2005.
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none of the Caddo Lake study participants had blood Hg levels 

above the benchmark dose level (BMDL) of 5.8 μg/L (one of the 

several used by EPA in the calculation of the MeHg RfD). The 

BMDL is not a “no effect” level. Rather it is an effect level 

for a percentage of the population. The EPA has noted in 

correspondence with TCEQ that, as an exposure study, the Caddo 

Lake study may be representative of the surrounding population; 

however, the sample size is very small. It is not appropriate to 

extrapolate from Caddo Lake to larger regional or national 

populations.

The EPA is aware of the possibility of both interactions 

among environmental contaminants and cumulative effects of 

pollutants that produce the same adverse endpoint. The EPA 

guidance exists for dealing with such scenarios.242,243,244,245 The 

 

242 U.S. EPA. 1986. Guidelines for the Health Risk Assessment of 

Chemical Mixtures. U.S. Environmental Protection Agency, Office 

of Research and Development, Washington, D.C. September. 

EPA/630/R-98/002. Available at 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=2256

243 U.S. EPA. 1999. Guidance for Performing Aggregate Exposure 

and Risk Assessments. U.S. Environmental Protection Agency, 

Office of Pesticide Programs, Washington, D.C. October. 

Available at http://www.pestlaw.com/x/guide/1999/EPA19991029A.html

244 U.S. EPA. 2000a. Supplementary Guidance for Conducting Health 

Risk Assessment of Chemical Mixtures. U.S. Environmental 

Protection Agency, Risk Assessment Forum, Washington, D.C. 

EPA/630/R-00/002. Available at 

http://www.epa.gov/ncea/raf/pdfs/chem_mix/chem_mix_08_2001.pdf

245 U.S. EPA. 2003a. Framework for Cumulative Risk Assessment. 

Risk Assessment Forum, U.S. Environmental Protection Agency. 

Washington, D.C. EPA/630/P-02/001F. EPA/600/P-02/001F. Available 
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Agency’s concern with the likelihood of human exposure to 

multiple contaminants is reflected in the multi-chemical scope 

of the rulemaking. However, the EPA focused the technical 

analyses supporting the proposed regulation on effects of 

individual pollutants rather than cumulative effects. 

The EPA disagrees with commenters suggesting that the RfDbased HQ is inappropriate. The SAB “agreed that EPA’s 

calculation of a hazard quotient for each watershed included in 

the assessment is appropriate as the primary means of expressing 

risk,” and that “because the RfD from which the HQ is calculated 

is an integrative metric of neurodevelopmental effects of 

methylmercury, it constitutes a reasonable basis for assessing 

risk.”

246

The SAB also recommended that EPA revise the Hg Risk TSD to 

include additional qualitative discussion about uncertainty in 

the revised Hg Risk TSD. Specifically, the SAB recommended that 

EPA revise the Hg Risk TSD “to better explain the methods and 

choices made in the analysis, and analytical results, and where 

the uncertainties lie.” The SAB noted several uncertainties 

related to the RfD. The EPA agrees with this recommendation and 

included a more complete discussion of these uncertainties in 

the revised Hg Risk TSD.

 

at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=54944

246 U.S. EPA-SAB, 2011.
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The EPA disagrees that the IQ metric threshold is 

questionable. The SAB concluded that it was reasonable to 

consider a loss of >1 or >2 IQ points a public health concern. 

The SAB stated, “The Panel agreed that if IQ loss is retained in 

the risk assessment despite these reservations, a loss of one or 

two points would be an appropriate benchmark.”

247 The SAB further 

comments in their report: “The consensus is that if IQ were to 

be used, then a loss of 1 or 2 points as a population average is 

a credible decrement to use for this risk assessment. This 

metric seems to be derived from the lead literature and was peer 

reviewed by the Clean Air Scientific Advisory Committee (U.S. 

EPA CASAC 2007).248 Although its applicability to methylmercury 

is questionable, the size of the decrement is justified based on 

the extensive analyses available from the literature reviewed by 

CASAC.”

249 As noted in other studies,250,251 a decrease of 1-2 

 

247 U.S. EPA-SAB, 2011.

248 U.S. Environmental Protection Agency – Science Advisory Board 

(U.S. EPA-SAB). 2007. Clean Air Scientific Advisory Committee’s 

(CASAC) Review of the 1st Draft Lead Staff Paper and Draft Lead 

Exposure and Risk Assessments. EPA-CASAC-07-003. March. 

Available on the internet at 

http://yosemite.epa.gov/sab/sabproduct.nsf/989B57DCD436111B85257

2AC0079DA8A/$File/casac-07-003.pdf

249 U.S. EPA-SAB, 2011.

250 Axelrad, D. A.; Bellinger, D. C.; Ryan, L. M.; Woodruff, T. 

J. 2007. “Dose-response relationship of prenatal mercury 

exposure and IQ: an integrative analysis of epidemiologic data.” 

Environmental Health Perspectives, 115, 609–615.

251 Bellinger DC. 2005. Neurobehavioral Assessments Conducted in 

the New Zealand, Faroe Islands, and Seychelles Islands Studies 
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points at the mean results in a much larger decrease in those 

with IQs that are much lower or higher than the mean. 

Although EPA disagrees that the IQ results are too 

uncertain to rely upon, the EPA acknowledges that IQ is not the 

most sensitive neurodevelopmental endpoint affected by MeHg 

exposure, as also noted by the SAB. The SAB recommended that the 

IQ analyses be retained but be de-emphasized in the 

documentation underlying the final regulation. The SAB 

concluded, “The Panel does not consider it appropriate to use IQ 

loss in the risk assessment and recommended that this aspect of 

the analysis be de-emphasized, moving it to an appendix where IQ 

loss is discussed along with other possible endpoints not 

included in the primary assessment. While the Panel agreed that 

the concentration-response function for IQ loss used in the risk 

assessment is appropriate, and no better alternatives are 

available, IQ loss is not a sensitive response to methylmercury 

and its use likely underestimates the impact of reducing 

methylmercury in water bodies.”

252 The EPA is following the SAB’s 

recommendation by deemphasizing the IQ analysis and placing that 

analysis in an appendix to the revised Hg Risk TSD. 

The SAB, however, supported the use of the IQ dose-response 

function calculated by EPA in the Hg Risk TSD. The SAB noted, 

 

of Methylmercury Neurotoxicity in Children. Report to the U.S. 

Environmental Protection Agency. EPA-HQ-OAR-2002-0056-6045.

252 U.S. EPA-SAB, 2011.
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“The function used came from a paper by Axelrad and Bellinger 

(2007) that seeks to define a relationship between methylmercury 

exposure and IQ. A whitepaper by Bellinger (Bellinger, 2005)253

describes the sequence of steps in relating methylmercury 

exposure to maternal hair mercury and then that to IQ. The 

Mercury Risk TSD furthers notes that IQ has shown utility in 

describing the health effects of other neurotoxicants. These are 

appropriate bases for examining a potential impact of reducing 

methylmercury on IQ, but the SAB does not consider these 

compelling reasons for using IQ as a primary driver of the risk 

assessment.”

254

The EPA disagrees that the Agency has overstated or failed 

to review the scientific literature on cardiovascular effects 

from MeHg exposure. As summarized in the preamble to the 

proposal, the EPA stated that the NAS study concluded that 

“Although the data base is not as extensive for cardiovascular 

effects as it is for other end points (i.e., neurologic effects) 

the cardiovascular system appears to be a target for MeHg 

toxicity in humans and animals.”

255 The EPA also stated that 

additional cardiovascular studies have been published since 

2000. The EPA did not develop a quantitative dose response 

assessment for cardiovascular effects associated with MeHg 

 

253 Bellinger, 2005.

254 U.S. EPA-SAB, 2011.

255 76 FR 25001
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exposures, as there is no consensus among scientists on the 

dose-response functions for these effects, and there is 

inconsistency among available studies as to the association 

between MeHg exposure and various cardiovascular system effects. 

In the future, the EPA may update the MeHg RfD and will review 

all of the relevant scientific literature available at that 

time, including data on all relevant endpoints, and weight of 

evidence for likelihood that MeHg produces specific effects in 

humans.

The EPA acknowledges the research regarding the 

effectiveness of fish advisories. However, the proposed 

regulation does not address the subject of fish advisories, 

consumer advice on fish or efficacy of such advice. The EPA 

rejects the commenter’s speculation regarding whether the 

estimated IQ impacts for the regulation are real. Adverse 

effects of in utero Hg exposure have been reported in 

populations in the U.S.256,257 In another study on neurobehavioral 

effects of prenatal exposure to MeHg through maternal 

consumption of seafood, adverse effects are observed for MeHg 

even without controlling for fish consumption.258 That study 

 

256 Oken et al., 2008,

257 Lederman et al., 2008.

258 Suzuki, K., Nakai, K., Sugawara, T., Nakamura, T., Ohba, T., 

Shimada, M., Hosokawa, T., Okamura, K., Sakai, T., Kurokawa, N., 

Murata, K., Satoh, C., and Satoh, H. 2007. “Neurobehavioral 

effects of prenatal exposure to methylmercury and PCBs, and 
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suggests that at normal Japanese dietary intake of MeHg and fish 

nutrients, the overall effect is adverse. While Japanese fish 

consumption and Hg exposure are both somewhat higher than the 

mean U.S. exposure, these levels are still within the 

distribution of U.S. consumers. 

Moreover, many studies show that beneficial effects of fish 

on both cardiovascular and neurodevelopmental health are 

decreased by concomitant exposure to MeHg. Several studies 

describe one or more aspects of exposure to fish nutrients and 

MeHg.259,260,261,262263,264,265 Recent studies266,267,268 and analyses 

 

seafood intake: neonatal behavioral assessment scale results of 

Tohoku study of child development.” Environ Res 110, 699-704.

259 Grandjean P, Bjereve K, Wihe P, and Sterewald u. 2001a. 

“Birthweight in a fishing community: significance of essential 

fatty acids and marine food contaminants.” In. J. Epidemiol.

30:1272-1278. 

260 Budtz-Jorgensen, E.; Grandjean, P.; Weihe, P. 2007. 

“Separation of risks and benefits of 16 seafood intake.” 

Environmental Health Perspectives. Vol. 115, 323-327.

261 Choi et al., 2008a. 

262 Choi et al., 2008b.

263 Oken et al., 2008.

“

264 Strain, J.J. et al. 2008. Associations of maternal long 

chain polyunsaturated fatty acids, methyl mercury, and infant 

development in the Seychelles Child Development Nutrition 

Study.” Neurotoxicology. 29(5): 776–782.

265 Suzuki, et al., 2007.

266 Oken et al., 2008.

267 Choi AL, Cordier S, Weihe P, Grandjean P. 2008a. “Negative 

confounding in the evaluation of toxicity: the case of 

methylmercury in fish and seafood.” Crit Rev Toxicol.

2008;38(10):877-93.

268 Choi AL, Budtz-Jørgensen E, Jørgensen PJ, Steuerwald U, Debes 

F, Weihe P, Grandjean P. 2008b. “Selenium as a potential 

protective factor against mercury developmental neurotoxicity.” 

Environ Res. May;107(1):45-52. Epub 2007 Sep 12.
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indicate the potential for nutrients in fish (particularly 

marine fish) to mask some of the observed adverse effects of 

MeHg. Because EPA did not adjust for potential confounding by 

nutrients in marine fish and mammals, the benchmark doses used 

in the RfD derivation may be underestimated. 

The EPA recognizes the potential for confounding of the 

effects of Hg on the developing nervous system by a range of 

nutrients and discusses this uncertainty in the revised Hg Risk 

TSD. Regarding selenium, the SAB commented that “one SAB member 

suggests the use of blood markers of selenium-dependent enzyme 

function, noting that methylmercury irreversibly inhibits 

selenium-dependent enzymes that are required to support vitalbut-vulnerable metabolic pathways in the brain and endocrine 

system. Impaired selenoenzyme activities would be observed in 

the blood before they would be observed in brain, but the effect 

is also expected to be transitory. The use of these measures is 

a minority view among the SAB members.”

269 The SAB did not 

express a consensus recommendation on adjustments to the risk 

estimates for exposure to selenium or other nutrients, noting 

that “there is not enough known about their quantitative impact 

to support a recommendation of a re-analysis.”

270

6. General comments on Hg Risk Assessment

 

269 U.S. EPA-SAB, 2011.

270 Id.
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Comment: Several commenters generally supported the Hg risk 

assessment, but several other commenters generally disagreed 

with the Hg risk assessment. One supporter stated that EPA 

reasonably determined that Hg emissions pose a public health 

hazard, correctly requested peer review of Hg risk analysis and 

correctly concluded EGU-attributable MeHg poses a hazard to 

public health at watersheds when considering all sources of Hg 

deposition and U.S. EGUs alone. Two commenters noted that the 

contribution of U.S. EGUs to total Hg deposition can 

significantly contribute to hundreds of watersheds, and U.S. EGU 

deposition alone may endanger sensitive populations near many of 

these watersheds. 

Several commenters claimed that overly conservative 

assumptions in the risk analysis render the results flawed and 

unreliable, including using CMAQ to model deposition, Mercury 

Maps, fish consumption rate and fish MeHg concentrations, overly 

stringent RFD, national-scale model, using poverty as a 

surrogate for subsistence fishing, assuming a subsistence fisher 

resides in most watersheds with fish tissue data, fishers only 

eat larger fish with high Hg concentrations, cooking loss 

adjustment, unrealistically high fish ingestion rates (a large 

fish meal every day), focused on the extremes of the 

distributions, cast many assumptions as an underestimate of the 
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Page 270 of 1103

effect despite evidence to the contrary, and created 

inappropriate metrics for risk that show no improvement despite 

significant Hg emissions reductions in the U.S. 

Several commenters cite Tetra Tech’s analysis that assessed 

Hg risk using different consumption rates, cooking factor, mean 

fish tissue concentrations, and EGU-attributable Hg deposition 

only, which showed considerably fewer watersheds that exceed an 

HQ of 1 at 2016 deposition levels. 

Several commenters claim that this regulation would not 

significantly reduce Hg exposure via fish consumption because 

EGU-attributable deposition is a small fraction of total 

deposition. One commenter stated that EPA’s data shows Hg 

emissions from U.S. EGUs have little influence on fish Hg 

concentrations despite a reduction of 41 tons of Hg in the U.S. 

between 2005 and 2016. One commenter requested that EPA 

accurately describe the low health risks posed by utility 

hazardous air pollutant emissions. One commenter stated that EPA 

did not consider scientific information showing that there is no 

straightforward connection between Hg emissions from U.S. EGUs 

to the Hg level in fish, which is dependent upon many 

environmental factors, such as sunlight and organic matter, pH, 

water temperature, sulfate, bacteria, and zooplankton present in 

the ecosystem. One commenter stated that there is not any 
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Page 271 of 1103

demonstrable evidence that anyone in the U.S. has suffered 

adverse health problems as a result of Hg emissions from coalfired EGUs. One commenter stated that EPA’s findings are similar 

to the 2000 findings where EPA found a plausible link between 

anthropogenic emissions of Hg from sources in the U.S. and MeHg 

in fish, and “plausible” is a euphemism for unproven.

Several commenters had recommendations for the Hg risk 

analysis. One commenter stated that more data from Florida 

should have been included because Florida is known to have a 

rich data set on fish Hg concentrations. One commenter stated 

that EPA should characterize general recreational angler fishers 

instead of subsistence fishers. One commenter claims that EPA 

made math errors in the Hg Risk TSD regarding the deposition in 

watersheds at specific percentiles. One commenter questioned 

EPA’s policy metrics used to characterize Hg risk. 

Several commenters stated that the Hg TSD is unclear and 

lacks detail, as noted by the SAB. One commenter stated that the 

SAB is critical of EPA’s efforts, stating that the SAB found it 

difficult to evaluate the risk assessment based solely upon Hg 

Risk TSD and recommended that EPA transparently explain the 

methods and uncertainties. One commenter stated that because of 

insufficient review time and the lack of detail in the Hg Risk 
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TSD, they could not assess key questions, such as the nationwide representativeness of the fish tissue data. 

One commenter stated the subset of watersheds considered in 

the analysis (i.e., with fish tissue data) have clearly higher 

U.S. EGU-attributable deposition than the distribution of all 

watersheds. 

One commenter stated EPA’s reporting of IQ point loss is 

erroneous and not relevant to informing policy, and the U.S. EGU 

contribution to risk is marginal as evidenced by the null values 

for the 50th percentile watershed.

One commenter notes that U.S. EGU-attributable emissions of 

Hg have decreased significantly between 2005 and 2016, but 

claims that this decrease does not appear to affect the risk 

results. 

Response: The purpose of the Hg risk assessment is not to assess 

the magnitude of risk reduction under the proposed rule, but 

rather to estimate the magnitude of absolute risk attributable 

to U.S. EGUs currently and following implementation of other 

applicable CAA requirements. That said, any potential risk 

reductions following implementation of the MACT rule itself 

would likely reflect a number of factors besides the national 

average U.S. EGU deposition value cited by the commenter. These 

additional factors include: (a) spatial gradients in the 
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magnitude of absolute U.S. EGU-attributable Hg deposition, (b) 

spatial gradients in the magnitude of reductions in Hg 

deposition linked to the rule, (c) availability of measured fish 

tissue Hg levels in the vicinity of U.S. EGUs experiencing 

larger Hg emission reductions to support risk modeling, and (d) 

the potential for subsistence fishing activity at watersheds in 

the vicinity of U.S. EGUs experiencing larger reductions in Hg 

emissions (also required to support risk modeling). It is also 

important to point out that while the national average U.S. EGUattributable Hg deposition (for the 2016 scenario – see revised 

Hg Risk TSD) is two percent, values range up to 11 percent for 

the 99th percentile watershed. This illustrates the substantial 

spatial variation in U.S. EGU-attributable Hg deposition, which 

translates into spatial variation in the magnitude of U.S. EGUattributable subsistence fisher risk.

The SAB conducted a comprehensive peer review of all of 

EPA’s assumptions in the Hg Risk TSD, and concluded that “the 

SAB supports the overall design of and approach to the risk 

assessment and finds that it should provide an objective, 

reasonable, and credible determination of the potential for a 

public health hazard from Hg emitted from U.S. EGUs.”

271

Furthermore, the SAB concluded, “The SAB regards the design of 

the risk assessment as suitable for its intended purpose, to 

 

271 U.S. EPA-SAB, 2011.
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inform decision-making regarding an “appropriate and necessary 

finding” for regulation of hazardous air pollutants from coal 

and oil-fired EGUs, provided that our recommendations are fully 

considered in the revision of the assessment.”

272 Although the 

SAB did indicate difficulty in evaluating the risk assessment 

based solely on the Hg Risk TSD, the panel obtained additional 

information from EPA through the peer review process and 

determined that “the SAB supports the overall design of and 

approach to the risk assessment and finds that it should provide 

an objective, reasonable, and credible determination of the 

potential for a public health hazard from mercury emitted from 

U.S. EGUs.”

273 The primary advice of the SAB panel was that EPA 

should “revise the Technical Support Document to better explain 

the methods and choices made in the analysis, and analytical 

results, and where the uncertainties lie.”

274 The EPA has revised 

the Hg Risk TSD as part of the final rulemaking to address the 

SAB’s recommendations and has made that revised Hg Risk TSD 

available in the rule docket. 

The SAB concurred with EPA’s analytical assumptions and 

overall study design for the Hg Risk TSD, including the RfDbased HQ approach, fish tissue data, 75th percentile size fish, 

Mercury Maps assumption, and consumption rates. Based on the SAB 

 

272 Id.

273 Id.

274 Id.
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peer review, the EPA strongly disagrees with commenter 

statements that the results reported in the Hg Risk TSD are 

unreliable, overly conservative, extreme, inconsistent with EPA 

risk guidelines, or severely overstate risk based on the stated 

objectives of the analysis. The EPA has specifically addressed 

each of these assumptions in the previous sections of the 

preamble, and thus, does not repeat those responses here. Based 

on the review by the SAB, the EPA has accurately described the 

health risks posed by utility hazardous air pollutant emissions 

and disagrees with the commenter’s statement that EPA has not 

provided any demonstrable evidence to show that adverse health 

risks exist. The EPA has applied peer reviewed modeling to 

estimate the deposition of Hg attributable to U.S. EGUs. The EPA 

asserts that these metrics demonstrate a clear hazard to public 

health from Hg emissions from U.S. EGUs. 

The EPA thoroughly evaluated the Tetra Tech analysis. The 

EPA does not agree that the analysis by Tetra Tech uses 

assumptions that are “more reasonable”, and the SAB agreed that 

all of EPA’s assumptions in the Hg Risk TSD are reasonable and 

appropriate. The EPA asserts that Tetra Tech’s analysis does not 

fully cover subsistence fishers likely to experience elevated 

U.S. EGU-related Hg exposure. Specifically, the risk estimate 

cited in the comment reflects application of a number of 
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behavioral assumptions that provide significantly less coverage 

for higher risk subsistence fishers. Fish consumption surveys 

cited in the revised Hg Risk TSD suggest that higher percentile 

subsistence fishers eat more than twice the level of fish 

assumed by Tetra Tech. Tetra Tech’s analysis also used the 

median fish tissue levels, but it is reasonable to assume that 

subsistence fishers would target somewhat larger fish to 

maximize the volume of edible meat per unit time spent fishing. 

Tetra Tech’s analysis also assumed that cooking fish did not 

concentrate Hg, but a number of studies discussed in the revised 

Hg Risk TSD explicitly provide adjustment factors involving a 

higher unit concentration following preparation. Taken together, 

Tetra Tech’s analysis does not address the stated goal of the 

risk assessment to assess the nature and magnitude of risk for 

those individuals likely to experience the greatest risk 

associated with exposure to U.S. EGU-attributable Hg. 

The EPA disagrees with the commenter’s assertion that this 

rule will not affect risks associated with Hg exposure. Hg from 

U.S. EGUs contributes to the levels of MeHg in fish across the 

country and consumption of contaminated fish can lead to 

increased risk of adverse health effects. The EPA has shown in 

the RIA (Chapter 5) that this rule will reduce Hg levels in 

fish. 
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The EPA acknowledges that U.S. EGUs contribute only a small 

fraction of total Hg deposition in the U.S. However, U.S. EGUs 

remain the largest emitter of Hg in the U.S., and the revised Hg 

Risk TSD shows that U.S. EGU-attributable Hg deposition results 

in up to 29 percent of modeled watersheds with populations

potentially at-risk. Our analyses show that of the 29 percent of 

watersheds with population at-risk, in 10 percent of those 

watersheds U.S. EGU deposition alone leads to potential 

exposures that exceed the MeHg RfD, and in 24 percent of those 

watersheds, total potential exposures to MeHg exceed the RfD and 

U.S. EGUs contribute at least 5 percent to Hg deposition. 

Mercury risk is increasing for exposures above the RfD, and as a 

result, any reductions in Hg exposures in locations where total 

exposures exceed the RfD can result in reduced risks. While 

these reductions in risk may be small for most populations and 

locations, in some watersheds and for some populations, 

reductions in risk may be greater. 

The SAB also directly addressed the question of the nationwide representativeness of the fish tissue MeHg data in the 

national Hg risk assessment. The SAB concluded, “Although the 

SAB considers the number of watersheds included in the 

assessment adequate, some watersheds in areas with relatively 

high mercury deposition from U.S. EGUs were under-sampled due to 
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lack of fish tissue methy[l]mercury data. The SAB encourages the 

Agency to contact states with these watersheds to determine if 

additional fish tissue methylmercury data are available to 

improve coverage of the assessment.”

275 In response to the SAB’s 

recommendations, the EPA obtained additional fish tissue sample 

data from several states, particularly Pennsylvania, Wisconsin, 

Minnesota, New Jersey, and Michigan. This additional data 

increased the total number of watersheds assessed in the 

analysis by 33 percent nationally. In Florida, the EPA assessed 

the Hg-related health risk for 40 watersheds. Because EPA did 

not find any additional fish tissue data for watersheds in 

Florida that could be incorporated into the analysis, the total 

number of watersheds in Florida assessed in the revised Hg Risk 

TSD remains the same as the Hg Risk TSD at proposal. 

The EPA disagrees with the commenter that there were errors 

in the Hg Risk TSD. Instead, the commenter has misinterpreted 

how EPA calculated the percentiles. The percentile (and mean) 

values presented in Table ES-1 for total and U.S. EGUattributable Hg deposition are not matched by watershed. In 

other words, the EPA queried for the percentiles (and mean) 

provided for total Hg deposition and presented those percentiles 

and then separately estimated the percentiles for U.S. EGUattributable Hg. Therefore, the total and U.S. EGU-attributable 

 

275 U.S. EPA-SAB, 2011.
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values for the 99th percentile do not necessarily occur at the 

same watershed. The EPA has provided additional clarification in 

the revised Hg Risk TSD. 

The EPA agrees with the commenter that MeHg levels in fish 

depend on a complicated set of environmental factors, and EPA 

acknowledged this in the revised Hg Risk TSD. Furthermore, the 

EPA acknowledges that total Hg fish tissue levels are not 

correlated with levels of total Hg deposition when looking

across watersheds because this relationship is highly dependent 

on the methylation potential at the specific waterbody, which is 

affected by pH, sulfate deposition, turbidity, etc. However, 

several recent studies276,277,278 show, and the SAB agrees, that it 

is appropriate for EPA to assume that changes in Hg deposition 

are linearly associated with changes in fish tissue 

concentration. In addition, the EPA agrees that the subset of 

watersheds in the risk analysis have somewhat higher U.S. EGU 

deposition than the distribution of all watersheds, but EPA 

disagrees that oversampling of high deposition watersheds is 

inappropriate. 

The EPA does not agree that there is no improvement in fish 

Hg concentrations between 2005 and 2016, or that there will be 

no further improvement from decreasing Hg emissions from U.S. 

 

276 Orihel et al., 2007.

277 Orihel et al., 2008.

278 Harris et al., 2007.
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EGUs from the baseline in 2016. Although total risk from all Hg 

exposures will remain elevated in much of the U.S., much of that 

risk is associated with global, non-U.S. Hg emissions. U.S. EGUs 

remain the largest source of Hg emissions in the U.S., and 

reductions in those emissions will result in reduced Hg 

deposition in many highly impacted watersheds. As shown in the 

revised Hg Risk TSD, average U.S. EGU-attributable fish tissue 

Hg concentrations is estimated to decrease by 44 percent between 

2005 and 2016. Although we did not remodel risk for the 2005 

scenario in the revised Hg Risk TSD, we estimated at proposal 

that the total percent of modeled watersheds with populations 

potentially at-risk from Hg emissions from U.S. EGUs exceeding 

either risk metric (i.e., U.S. EGUs alone or total potential 

exposures to MeHg exceed the RfD and U.S. EGUs contribute at 

least 5 percent) would decline from 62 percent in 2005 to 28 

percent in 2016. This projected decline is primarily due to a 

combination of additional pollution control technologies 

installed to comply with federal regulations, such as CSAPR, and 

changing fuels, such as the shift to natural gas. 

The EPA disagrees that IQ loss is erroneous or irrelevant 

to informing policy, but EPA has moved that analysis to an 

appendix in the revised Hg Risk TSD, per the SAB’s 

recommendation. The EPA disagrees that the IQ effects at the 50th
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percentile watershed are useful in determining that there is not 

a hazard to public health because EPA’s stated goal of the risk 

assessment was to focus on populations likely to experience 

relatively higher exposures to U.S. EGU-attributable Hg. 

We also disagree with those commenters that point to the 

SAB’s statements concerning the clarity of the Hg Risk TSD to 

suggest that the public did not have an ample opportunity to 

comment on the Hg risk assessment. Although it is correct that 

the SAB said the Hg Risk TSD was difficult to evaluate until EPA 

staff explained it at the public meeting in June 2011, we note 

that the commenters that assert that this issue amounts to a 

violation of CAA section 307(d) notice requirements made 

detailed technical comments, including many of the same comments 

as the SAB. Furthermore, the EPA provided notice of the peer 

review in the preamble to the proposed rule and a number of 

Federal Register notices advised the public of the peer review 

process and all the meetings were open to the public for comment 

and participation and the minutes of those meetings were posted 

on the SAB website. The minutes for the June 2011 meeting, 

during which EPA provided clarifying information, were available 

well within the public comment period for the proposed rule. For

these reasons, we maintain that the public was provided an 

adequate opportunity to comment on the Hg risk assessment.
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e. Non-Hg HAP Case Studies

1. Emissions for non-Hg case studies 

Comment: The commenters raised concerns about a wide variety of 

aspects of EPA’s approach for emissions used for the non-Hg case 

studies, including the use of an arithmetic mean for computing 

emission factors for representing emissions of untested units, 

the suggestion of statistical outliers in the Cr test data, the 

claim that metals content of the fuel is a indicator of flawed 

test data, the statistical approaches used by EPA to create 

emission factors, the absence in EPA’s approach of an equation 

that commenters claim better represents emissions values, that 

EPA’s approach to estimate Cr(VI) is flawed, and the lack of 

coal rank as a delineating factor for emission factor 

calculation. The commenters also suggested that EPA should 

revise stack parameters used for the case studies based on 

better available data.

Response: In response to the comments on the emission factors, 

the EPA has undertaken additional analysis to address all 

commenter concerns. The EPA disagrees with commenter’s 

criticisms of emission factors based on arithmetic means, and 

EPA demonstrates that the use of an arithmetic mean provides the 

most representative result. The EPA analysis has found that the 

geometric mean approach recommended by the commenter always 
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under predicts actual emissions by an average of more than 

seventy percent. The EPA agrees with commenters’ recommendations 

to use statistical outlier tests, but has applied tests 

different from those suggested by the commenters. As further 

explained in the response to comments document in the docket, 

this approach did not eliminate the Cr test data from the Cr 

emission factors used for some of the case study emissions.

The EPA disagrees with commenters’ assertions that the 

metal content of the coal is a basis for invalidating the test 

results of high Cr emissions. The identification of sources 

whose measured emissions do not match the commenters’

preconceived idea of emissions behavior is not surprising. There 

are many possible explanations for these differences. For 

example, the inconsistency between the test data and the coal 

analysis could be due to any number of reasons including 

unrepresentative coal sampling, control device problems, 

degradation of the refractory, or sampling contamination. The 

idea that test data should be discarded because it does not 

match initial expectations is unfounded.

The EPA disagrees with the commenter recommendations for 

using an equation from AP-42, developed in part by the 

commenters. Based on analyses of metal emissions measured at the 

site compared to statistically predicted estimates, the EPA 
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concluded that measured emissions test data better predict 

actual emissions, and emission factors based on the arithmetic 

mean are a reasonable method to estimate emissions when test 

data are not available. The EPA analysis of the ICR data has 

found that the emissions equation recommended by the commenter 

is not a good predictor of actual EGU emissions. The EPA also 

disagrees with commenters’ concerns about the assumption that 12 

percent of the Cr will be Cr(VI) for every coal-fired unit, 

which was specifically supported by the peer review on the 

approach for estimating cancer risks associated with Cr and Ni 

emissions. The EPA disagrees with the commenter’s assertion that 

any impact of scrubbers will impact the case study analyses. In 

EPA’s revised case study analysis, 6 facilities have risk 

greater than 1 in a million, and of these, four facilities have 

Cr as the risk driver (James River, Conesville, TVA Gallatin, 

and Dominion – Chesapeake Bay). For these facilities, none of 

the units contributing the bulk of the Cr emissions have 

scrubbers according to the data provided to EPA by those 

facilities, so scrubber impacts on Cr speciation is not relevant 

to EPA’s conclusions based on the non-Hg case studies. In any 

case, the EPA disagrees with the commenter’s conclusions about 

the impacts of scrubbers on Cr speciation and provides evidence 

that impacts of scrubbers on Cr speciation can have the opposite 
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effect on Cr(VI) fractions, concluding that EPA’s 12 percent 

assumption is somewhat conservative.

The EPA also disagrees that coal rank must be a factor in 

computing Cr emission factors for use in the case studies. The 

EPA’s analysis has demonstrated that coal rank appears to play 

no role in non-Hg metals emissions. The EPA’s newly revised 

emissions factor development procedures can isolate and compare 

subgroups based on control device type or coal rank; the ICR 

data were subjected to these tests and no statistical 

significance was found between coal rank groups.

Finally, the EPA agrees with one commenter’s 

recommendations on revised stack parameters for the case studies 

and has included these revisions in the case study modeling for 

the final rule.

2. General Comments on Non-Hg Risk Case Study 

Comment: One commenter stated that EPA’s case study assessment 

reaffirms the need to regulate HAP emitted by both coal and oilfired EGUs. The commenter noted that over 40 percent of the case 

studies conducted by EPA to quantify health hazards associated 

with the inhalation of non-Hg HAP indicated a cancer risk 

greater than or equal to the one in a million threshold level 

required to delist a source category under CAA section 112.
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One commenter stated that EPA’s case study assessment might 

be flawed by the use of “beta” tests versions of the AERMOD 

meteorological preprocessors (AERMINUTE and AERMET). The 

commenter obtained from EPA the meteorological data used for 

EPA’s assessment of the Conesville facility and processed these 

data with EPA’s current regulatory versions of these 

preprocessors, which differ from the beta version. According to 

the commenter, a comparison of the hourly wind speed and hourly 

wind direction data produced by the beta preprocessor and by 

current EPA preprocessors revealed numerous and often 

substantial disparities.

One commenter stated that EPA’s finding that only three 

coal-fired facilities and one oil-fired facility out of roughly 

440 coal-fired facilities and 97 oil-fired facilities in the 

U.S. indicated risk greater than one-in-a-million supports a 

finding that it is “appropriate” to regulate those four and not 

the other 537. Another commenter stated that EPA found only a 

“few” facilities that have estimated maximum cancer risks in 

excess of one in a million, and that this does not justify 

regulating all non-Hg HAP for all sources in this category.

One commenter stated that EPA’s discussion in the preamble 

to the proposed rule misleads the reader into believing that 

non-Hg HAP emissions from EGUs are associated with serious human 
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health effects. According to the commenter, the EPA’s discussion 

of the effects associated with excessive exposure to an 

individual HAP would lead the reader to believe that those 

effects inevitably occur from EGU emissions because EGU 

emissions have trace amounts of non-Hg HAP. 

One commenter stated that with the assumptions in the 

Utility Study, both in terms of conservative scientific 

estimates and overestimated amounts of oil burned by these 

units, the EPA concluded that the risks from oil-fired units 

would result in only one new cancer case every 5 years. The 

commenter does not believe that this level of risk warrants 

regulation under CAA section 112(n)(1)(A). 

Several commenters stated that even if the additional 

studies EPA performed were accurate, they hardly demonstrate 

that it is necessary and appropriate to regulate coal-fired EGU 

HAP under CAA section 112 because three sites nationwide show 

risks greater that one in a million, with the highest at eight 

in a million.

One commenter stated that the highest cancer risk estimated 

for coal-fired EGUs is still within the acceptable range used by 

EPA in other programs and is also far less than the background 

exposure risks the average person experiences. The background 

risk of developing cancer in a lifetime is approximately one in 
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three (0.33). According to EPA’s own data, the predicted added 

cancer risk of exposure to HAP from U.S. EGUs would change the 

background risk from 0.33 to 0.330001. This level of change is 

so minimal that it could not be observed in any health effects 

study that might be conducted.

One commenter stated that EPA conducted a health risk 

assessment on a limited number of facilities and found a “few”

facilities that have estimated maximum cancer risks in excess of 

one in a million. The commenter stated that, based on this 

limited health risk assessment, the EPA apparently decided that 

they were justified to regulate all non-Hg HAP for all sources 

in this category. 

Several commenters stated that EPA’s assumption implies 

that a person stays exactly at the center of a census tract for 

70 years and that a unit will operate in exactly the same manner 

for 70 years is unrealistic. The commenters suggest that Tier 3 

risk assessment is warranted or a lifetime exposure adjustment 

is needed.

One commenter asserts that because the alleged health 

benefits are derived from total exposure, the EPA should explain 

how its numerical emission limit units, which would not directly 

restrict total exposure if heat inputs increase, redress this 

health concern. In its preamble, the EPA simply notes that its 
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emission limit units are consistent with, and allow for simple 

comparison to, other regulations.

One commenter questioned whether acid gas emissions limits 

for oil-fired units are “appropriate” or “necessary” because 

EPA’s new technical analyses do not indicate a health concern 

from acid gas emissions from oil-fired units. According to the 

commenter, the EPA identifies Ni as the main HAP of concern from 

oil-fired units, even though cancer-related inhalation risks 

were well below the RfCs and EPA states that significant 

uncertainty remains as to whether those emissions present a 

health concern. 

Response: The EPA agrees with the commenter that the non-Hg HAP 

risk assessment confirms the appropriate and necessary finding.

The EPA disagrees that EPA’s case study assessment is 

flawed by the use of beta versions of AERMINUTE and AERMET. The 

EPA remodeled the case study facilities using the current 

versions of AERMINUTE (version 11059), AERMET (version 11059), 

and AERMOD (version 11103). Although there were differences in 

the number of calm and missing winds in the current 

AERMINUTE/AERMET output compared to the beta version, the 

resulting risks differed by less than two percent, on average. 

For Conesville, which had the largest difference in calms 

between the beta and current versions of AERMINUTE/AERMET, the 
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risks differed by three percent. For the final rule, the case 

study facilities have been modeled with the current available 

versions of AERMINUTE, AERMET, and AERMOD.

The EPA disagrees with the commenter that having only a few 

case study facilities exceeding one in a million risk 

invalidates the “appropriate finding”. The 16 facilities EPA 

selected as case studies for assessment may not represent the 

highest-emitting or highest-risk sources. Although case study 

facility selection criteria included high estimated cancer and 

non-cancer risks using the 2005 NEI data, high throughput, and 

minimal emission control, another necessary criterion was the 

availability of Information Collection Request (ICR) data for 

the EGUs at those facilities (or for similar EGUs at other 

facilities). Because the ICR data were collected for the purpose 

of developing the MACT standards, the ICR was targeted towards 

better performing sources for non-Hg metal HAP, acid gas HAP, 

and organic HAP, with a smaller set of random recipients. 

Therefore, facilities for which ICR data were available may not 

represent the highest-emitting sources. The EPA’s assessment of 

the case study facilities for the proposed rule concluded that 

three coal-fired facilities and one oil-fired facility had 

estimated lifetime cancer risks greater than one in a million. 

For the final rule, revisions were made to the 16 case studies 
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based on comments received, and the results indicate that 5 

coal-fired facilities and 1 oil-fired facility had estimated 

lifetime cancer risks greater than 1 in a million. The EPA 

maintains that its finding that more than 30 percent of the case 

study facilities had a cancer risk greater than one in a million

is sufficient to support the appropriate finding. 

The EPA disagrees with the commenter’s assertion that the 

health effects associated with exposures to non-Hg HAP from U.S. 

EGUs are mischaracterized in the preamble to the proposed rule. 

The discussion of the health effects of non-Hg HAP provided in 

the preamble includes general information on the potential 

health effects associated with a broad range of exposure 

concentrations (from low to high levels) of the various non-Hg 

HAP (some of which have been determined to be carcinogenic to 

humans) based on peer reviewed scientific information extracted 

from priority sources such as IRIS, Cal EPA and ATSDR health 

effects assessments.

The EPA disagrees with the commenter’s characterization of 

the Utility Study. The Utility Study represented the highestquality factual record of information available at the time 

regarding EGU emissions and risks. Further, the EPA’s revised 

risk assessments of 16 case studies, performed with more recent 

data and refined scientific methods, indicate that there are six 
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U.S. EGU facilities that pose estimated inhalation cancer risks 

greater than 1 in a million. The EPA maintains that the findings 

of the case studies are one element that independently supports 

our determination that it remains appropriate and necessary to 

regulate EGUs under CAA section 112.

The EPA does not agree with the commenter who suggested 

that EPA should interpret the results of the non-Hg HAP risk 

analysis in the context of background cancer risk. As explained 

in the preamble to the proposed rule, the EPA reasonably looked 

to the cancer risk threshold established under CAA section 

112(c)(9)(B)(1) for delisting a source category as an indicator 

of the level of cancer risk that was appropriate to regulate 

under CAA section 112. The commenters comparison of the cancer 

risk from EGUs as compared with the risk of contracting cancer 

from unknown sources is not the standard Congress established 

for evaluating HAP emission risk and the commenter has provided 

no support for its contention that the Agency should evaluate 

risk in that manner. The EPA maintains that the analysis was 

reasonable. 

The EPA does not agree with the commenter’s implication 

that EPA must make a facility-specific finding for each HAP for 

each source and then only regulate individual EGU facilities for 

the individual HAP that identified as causing an identified 
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hazard to public health or the environment. That approach is not 

required under CAA section 112(n)(1) or anywhere under CAA 

section 112, and it would be virtually impossible to undertake 

such an effort. For these reasons, the EPA does not agree with 

the commenter and maintains that the appropriate and necessary 

finding is reasonably supported by the record and consistent 

with the statute for all the reasons set forth in the preamble 

to the proposed rule and this final action.

The EPA disagrees that an exposure adjustment is needed to 

account for conditions changing over 70 years because it runs 

counter to the long-standing approach that EPA has taken to 

estimate the maximum individual risk, or MIR. The MIR is defined 

by EPA’s Benzene NESHAP regulation of 1989279 and codified by CAA 

section 112(f) as the lifetime risk for a person located at the 

site of maximum exposure 24 hours a day, 365 days a year for 70 

years (e.g., census block centroids). The MIR is the 

metric associated with the determination of whether or not a 

source category may be delisted from regulatory consideration 

under CAA section 112(c)(9). The MIR is the risk metric used to 

characterize the inhalation cancer risks associated with the 

case study facilities. The EPA used the annual average ambient 

air concentration of each HAP at each census block centroid as a 

surrogate for the lifetime inhalation exposure concentration of 

 

279 54 FR 38044
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all the people who reside in the census block. The EPA has used 

this approach to estimate MIR values in all of its risk 

assessments to support risk-based rulemakings under CAA section 

112 to date.

The EPA disagrees with the commenter’s assertion that the 

numerical emission limits being promulgated in today’s final 

rule must be justified on their ability to redress the health 

concerns that were identified as the basis for regulating EGUs. 

The emission limits in today’s rule are technology-based, as 

prescribed under CAA section 112, and do not need to be 

justified based on their ability to protect public health. 

Regarding potential health concerns, the EPA has up to 8 years 

after the promulgation of the technology-based emission limits 

for EGUs to determine whether the regulations protect public 

health with an ample margin of safety. If the regulations do 

not, the CAA directs EPA to promulgate additional more stringent 

standards (within the prescribed 8 years) to achieve the 

appropriate level of public health protection.

Furthermore, the EPA reasonably concluded that it was 

appropriate and necessary to regulate oil-fired EGUs in 2000, 

and EPA confirmed that conclusion was proper with the analysis 

set forth in the preamble to the proposed rule. Certain 

commenters question the determination based on their views of 
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how the Agency can and should exercise its discretion. The EPA 

disagrees with these commenters and stands by the determination 

for the reasons set forth in the preamble to the proposed rule. 

The EPA also stands by the determination that the maximum cancer 

risks posed by emissions of oil-fired EGUs are greater than one 

in a million, due primarily to emissions of Ni compounds. Based 

on our analysis, we are unable to delist oil-fired EGUs. 

3. Ni Risk

Comment: Several commenters stated that the assumptions 

regarding the speciation and carcinogenic potential of Ni 

compounds used in EPA’s inhalation risk assessment of the case 

study facilities are overly conservative and likely to overstate 

the risks. With respect to Ni speciation, the commenters stated 

that there are substantial uncertainties regarding the species 

of Ni being emitted and the risk of such emissions, and that EPA 

has made ultraconservative assumptions aimed at overestimating 

the risk. The commenters stated that assigning the same 

carcinogenic potency of Ni subsulfide to other forms of Ni is 

overly conservative and inconsistent with the best available 

evidence.

Response: The EPA disagrees with the commenters’ assertion that 

it is impossible to give an accurate assessment of the risks to 

human health from Ni emissions from EGUs, and maintains that its 
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assessment of the potential inhalation risks from EGU emissions 

of Ni compounds is scientifically valid, reasonable, and based 

on the best-available current scientific understanding. To that 

end, in July 2011, the EPA completed an external peer review 

(using three independent expert reviewers) of the methods used 

to evaluate the risks from Ni and Cr compounds emitted by 

EGUs.280 There were two charge questions relating to Ni in that 

review. First, do EPA’s judgments related to speciated Ni 

emissions adequately take into account available speciation 

data, including recent industry spectrometry studies? Second, 

based on the speciation information available and what is known 

about the health effects of Ni compounds, and taking into 

account the existing URE values (i.e., values derived by the 

Integrated Risk Information System,281 California Department of 

Health Services,282 and the Texas Commission on Environmental 

Quality283), which of the following approaches to derive unit 

risk estimates would result in a more accurate and defensible 

characterization of risks from exposure to Ni compounds?

 

280 U.S. EPA, 2011c.

281 U.S. EPA, 1991.

282 California Department of Health Services (CDHS) 1991. Health 

Risk Assessment for Nickel. Air Toxicology and Epidemiology 

Section, Berkeley, CA. Available online at 

http://oehha.ca.gov/air/toxic_contaminants/html/Nickel.htm.

283 Texas Commission on Environmental Quality (TCEQ), 2011. 

Development Support Document for nickel and inorganic nickel 

compounds. Available online at 

http://www.tceq.state.tx.us/assets/public/implementation/tox/dsd

/final/june11/nickel_&_compounds.pdf
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1. To continue using the same approach as that developed for 

use in the 2000 NATA, which consists of using the IRIS URE 

for nickel subsulfide and assuming that nickel subsulfide 

constitutes 65 percent of the mass emissions of all Ni 

compounds.

2. To consider a more health-protective approach, based on the 

consistent views of the most authoritative scientific 

bodies (i.e., NTP in their 12th ROC, IARC, and other 

international agencies) that consider Ni compounds to be 

carcinogenic as a group.

3. To make the same assumptions as in option 2, but 

considering alternative UREs derived by the CDHS or TCEQ.

In responding to these peer review questions, two of the 

reviewers agreed with the views of the most authoritative 

scientific bodies, which consider Ni compounds carcinogenic as a 

group. These reviewers, therefore, did not focus on the 

availability of Ni speciation profile data. The third reviewer 

recommended that EPA review several manuscripts on Ni speciation 

profiles showing that sulfidic Ni compounds (which the reviewer 

considered as the most potent carcinogens) are present at low 

levels in emissions from EGUs.

Nickel and Ni compounds have been classified as human 

carcinogens by national and international scientific bodies 
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including the IARC,284 the World Health Organization,285 and the 

European Union’s Scientific Committee on Health and 

Environmental Risks.

286 In their 12th Report of the Carcinogens, 

the NTP has classified Ni compounds as known to be human 

carcinogens based on sufficient evidence of carcinogenicity from 

studies in humans showing associations between exposure to Ni 

compounds and cancer, and supporting animal and mechanistic 

data. More specifically, this classification is based on 

consistent findings of increased risk of cancer in exposed 

workers, and supporting evidence from experimental animals that 

shows that exposure to an assortment of Ni compounds by multiple 

routes causes malignant tumors at various organ sites and in 

multiple species. The 12th Report of the Carcinogens states that 

the “combined results of epidemiological studies, mechanistic 

studies, and carcinogenesis studies in rodents support the 

concept that Ni compounds generate Ni ions in target cells at 

 

284 International Agency for Research on Cancer (IARC), 1990. 

IARC monographs on the evaluation of carcinogenic risks to 

humans. Chromium, nickel and welding. Vol. 49. Lyons, France: 

International Agency for Research on Cancer, World Health 

Organization Vol. 49:256.

285International Labour Organization/United Nations Environment 

Programme, World Health Organization (WHO), 1991. Nickel. In 

Environmental Health Criteria No 108 Geneva.

286European Commission, Scientific Committee on Health and 

Environmental Risks (SCHER), 2006. Opinion on: Reports on 

Nickel, Human Health part. SCHER, 11th plenary meeting of 04 May 

2006 

http://ec.europa.eu/health/ph_risk/committees/04_scher/docs/sche

r_o_034.pdf
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sites critical for carcinogenesis, thus allowing consideration 

and evaluation of these compounds as a single group”.

287 Although 

the precise Ni compound (or compounds) responsible for the 

carcinogenic effects in humans is not always clear, studies 

indicate that Ni sulfate and the combinations of Ni sulfides and 

oxides encountered in the Ni refining industries cause cancer in 

humans. There have been different views on whether or not Ni 

compounds, as a group, should be considered as carcinogenic to 

humans. Some authors believe that water soluble Ni, such as Ni 

sulfate, should not be considered a human carcinogen, based 

primarily on a negative Ni sulfate 2-year NTP rodent bioassay 

(which is different than the positive 2-year NTP bioassay for Ni 

subsulfide).288,289,290 Although these authors agree that the 

epidemiological data clearly supports an association between Ni 

and increased cancer risk, they sustain that the data are 

weakest regarding water soluble Ni. A recent review291 highlights 

 

287 NTP, 2011.

288 Oller A. Respiratory carcinogenicity assessment of soluble 

nickel compounds. Environ Health Perspect. 2002, 110:841-844.

289 Heller JG, Thornhill PG, Conard BR. New views on the 

hypothesis of respiratory cancer risk from soluble nickel 

exposure; and reconsideration of this risk’s historical sources 

in nickel refineries. J Occup Med Toxicol . 2009, 4:23.

290 Goodman JE, Prueitt RL, Thakali S, and Oller AR. The nickel 

iron bioavailability model of the carcinogenic potential of 

nickel-containing substances in the lung. Crit Rev Toxicol . 

2011, 41:142-174.

291 Grimsrud TK and Andersen A. Evidence of carcinogenicity in 

humans of water-soluble nickel salts. J Occup Med Toxicol. 2010. 
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the robustness and consistency of the epidemiological evidence 

across several decades showing associations between exposure to 

Ni and Ni compounds (including Ni sulfate) and cancer. 

Based on the views of the major scientific bodies mentioned 

above, and those of expert peer reviewers that commented on 

EPA’s approaches to risk characterization of Ni compounds, the 

EPA considers all Ni compounds to be carcinogenic as a group and 

does not consider Ni speciation or Ni solubility to be strong 

determinants of Ni carcinogenicity. With regards to non-cancer 

effects, comparative quantitative analysis across Ni compounds 

indicates that Ni sulfate is as toxic or more toxic than Ni 

subsulfide or Ni oxide.292,293

Regarding the second charge question, two of the reviewers 

suggested using the URE derived by TCEQ for all Ni compounds as 

a group, rather than the one derived by IRIS specifically for Ni 

subsulfide. The third reviewer did not comment on alternative 

approaches. The EPA decided to continue using 100 percent of the 

current IRIS URE for Ni subsulfide because IRIS values are at 

the top of the hierarchy with respect to the dose response 

information used in EPA’s risk characterizations, and because of 

 

5:1-7. Available online at http://www.ossupmed.com/content/5/1/7.

292 Haber LT, Allen BC, Kimmel CA. Non-Cancer Risk Assessment for 

Nickel Compounds: Issues Associated with Dose-Response Modeling 

of Inhalation and Oral Exposures. Toxicol Sci. 1998. 43:213-229.

293 NTP, 1996.
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the concerns about the potential carcinogenicity of all forms of 

Ni raised by the major national and international scientific 

bodies. Nevertheless, taking into account that there are 

potential differences in toxicity and/or carcinogenic potential 

across the different Ni compounds, and given that there have 

been two URE values derived for exposure to mixtures of Ni 

compounds that are 2-3 fold lower than the IRIS URE for Ni 

subsulfide, the EPA also considers it reasonable to use a value 

that is 50 percent of the IRIS URE for Ni subsulfide for 

providing an estimate of the lower end of a plausible range of 

cancer potency values for different mixtures of Ni compounds.

4. Cr Risk

Comment: One commenter stated there are several problems with 

EPA’s analysis related to the fact that Cr emissions were 

evaluated as being entirely Cr(VI). The commenter stated that 

not all of the emitted Cr will remain in the hexavalent form by 

the time it reaches the target population, and that some may be 

converted to the much less toxic (and noncarcinogenic) trivalent 

species. The commenter also stated that the concentration levels 

considered in the case study assessment are far below 

occupational levels. The commenter concluded that EPA’s cancer 

estimates should, therefore, be looked on with some skepticism. 

Another commenter stated that EPA’s estimate of 12 percent 
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Cr(VI) from coal-fired EGUs is unsupported, and that EPA failed 

to recognize that Cr(VI) is highly water-soluble and is easily 

reduced to Cr(III) in the presence of SO2 in a low pH 

environment. The resulting Cr(III) would be expected to 

precipitate out in a FGD. The commenter stated that the actual 

amount of Cr(VI) that would be present in the emissions from an 

EGU with a wet scrubber is likely to be far lower than the 12 

percent estimate made by EPA.

Several commenters questioned the validity of the chronic 

inhalation study by EPA because of (1) the use of surrogate 

speciated Cr emissions data instead of actual emissions data, 

(2) the assumption that units were run 100 percent of the time 

which is impossible, (3) dispersion modeling was used that is 

biased towards over predicting downwind impacts, and (4) 

estimated ambient concentrations were utilized as substitutes 

for real exposure concentrations for all people within a census 

block.

Response: The EPA disagrees with the commenters’ assertion that 

all Cr was considered to be hexavalent. As discussed in “Methods 

to Develop Inhalation Cancer Risk Estimates for Chromium and 

Nickel Compounds,”

294 existing test data for utility and 

industrial boilers indicate that Cr(VI) is, on average, 12 

percent of total Cr from coal-fired boilers. This document 

 

294 U.S. EPA, 2011c.
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underwent peer review by three external reviewers, and all three 

reviewers considered EPA’s use of the values to be reasonable 

given the limited data available for Cr speciation profiling. 

The EPRI inhalation study for coal-fired boilers also used the 

12 percent value.

The EPA also disagrees that units were assumed to operate 

100 percent of the time. The dispersion modeling performed for 

the case study facilities used hourly heat input as a 

temporalization factor for estimating hourly emissions, and in 

some cases hourly heat inputs (and emissions) were zero or very 

low. The commenter provided no data or information to support 

their claim that the dispersion modeling EPA used is biased 

towards overestimating downwind impacts.

The EPA disagrees with the commenters’ assertion that “real 

exposure concentrations for all people within a census block”

must be considered because it runs counter to the long-standing 

approach that EPA has taken to estimate the maximum individual 

risk, or MIR. The MIR is defined by EPA’s Benzene NESHAP 

regulation of 1989295 and codified by CAA section 112(f) as the 

lifetime risk for a person located at the site of maximum 

exposure 24 hours a day, 365 days a year for 70 years (e.g., 

census block centroids). The MIR is the metric associated with 

the determination of whether or not a source category may be 

 

295 54 FR 3804
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delisted from regulatory consideration under CAA section 

112(c)(9). The MIR is the risk metric used to characterize the 

inhalation cancer risks associated with the case study 

facilities. The EPA used the annual average ambient air 

concentration of each HAP at each census block centroid as a 

surrogate for the lifetime inhalation exposure concentration of 

all the people who reside in the census block. The EPA has used 

this approach to estimate MIR values in all of its risk 

assessments to support risk-based rulemakings under CAA section 

112 to date.

5. Acid Gas Risk 

Comment: One commenter stated that acid gas emissions from oilfired EGUs are not of the magnitude that triggered EPA’s 

decision to regulate EGUs in general, raising the question of 

whether reduction (or even total elimination) of acid gas 

emissions from oil-fired EGUs could have any significant effect 

on EPA’s goals of reducing non-cancer health risk or 

acidification of sensitive ecosystems in the U.S.

Several commenters stated that acid gas concentrations 

estimated in the case study facility assessment and the Utility 

Study do not exceed human health thresholds of concern. Two 

commenters stated that HCl emissions are negligible compared to 
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other primary emissions (such as SO2) that can lead to potential 

acidification of ecosystems.

Response: We do not agree with commenter’s implication that 

Congress intended EPA to regulate only those HAP emissions from 

U.S. EGUs for which an appropriate and necessary finding is 

made, and commenter has cited no provision of the statute that 

states a contrary position. The EPA concluded that we must find 

it “appropriate” to regulate EGUs under CAA section 112 if we 

determine that a single HAP emitted from EGUs poses a hazard to 

public health or the environment. If we also find that 

regulation is necessary, the Agency is authorized to list EGUs 

pursuant to CAA section 112(c) because listing is the logical 

first step in regulating source categories that satisfy the 

statutory criteria for listing under the statutory framework of 

CAA section 112. See New Jersey, 517 F.3d at 582 (stating that 

“[s]ection 112(n)(1) governs how the Administrator decides 

whether to list EGUs...”). As we noted in the preamble to the 

proposed rule, D.C. Circuit precedent requires the Agency to 

regulate all HAP from major sources of HAP emissions once a 

source category is added to the list of categories under CAA 

section 112(c). National Lime Ass’n v. EPA, 233 F.3d 625, 633 

(D.C. Cir. 2000). 76 FR 24989. The EPA discusses in the preamble 

to the proposed rule and this final action its concerns with HCl 
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and other acid gas HAP emissions from EGUs and the Agency's 

approach for establishing section 112(d) standards for acid gas 

HAP.

6. EPRI Risk Analysis

Comment: Two commenters stated that a comprehensive tiered 

inhalation risk assessment (the EPRI study) using EPA-prescribed 

methods with improved emission factors, fuel data, and confirmed 

stack parameters did not identify significant health risks 

(cancer or non-cancer) among U.S. coal-fired power plants (as 

they existed in 2007). The commenters noted that these results

contrast with those presented by EPA for its non-Hg case studies 

on 16 (15 coal-fired) power plants. The commenters stated that 

several issues appear to underlie these differences, indicating 

the need for EPA to reevaluate its assessment and to undertake 

more refined (Tier 3) risk assessment for any facility of 

concern. Several commenters stated that for non-Hg HAP EPA 

produced one study on chronic inhalation risk assessment that 

identified three sites with cancer risks greater that one in a 

million for Cr(VI), which was authored by EPA staff and not peer 

reviewed. One commenter stated that EPA study is based on 

misinformation and overestimates assumptions, and that EPA has 

no data demonstrating health impacts from EGU emissions of nonHg HAP, or the benefit from reducing such emissions. Two 
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commenters stated that no benefits will be derived from the nonHg HAP emission reductions associated with the proposed rule 

because no non-Hg HAP health risks were proven, and that no 

showing was made that EGU non-Hg HAP emission levels reach 

levels associated with adverse health effects. Another commenter 

stated that EPA must complete a comparable and separate 

national-scale risk assessment for non-Hg metals in order to 

determine appropriateness of proposing emissions standards for 

non-Hg metals.

Response: The commenters are incorrect in the assertion that 

EPA’s case studies were performed with less rigor than the EPRI 

analysis. The EPRI analysis used a tiered approach to risk 

assessment, beginning with Tier 1 using EPA’s SCREEN3 dispersion 

model on all 470 coal-fired power plants in the U.S., and 

following with Tier 2 with EPA’s Human Exposure Model (which 

uses the AERMOD dispersion model) for plants with higher risks 

from the Tier 1 modeling. Although tiered risk assessment is an 

appropriate approach, the Tier 2 modeling could have been more 

refined. For example, more meteorological data could have been 

used and building downwash could have been considered. The EPRI 

analysis ostensibly concluded that the Tier 2 modeling with HEM 

was conservative, and that because the modeled risks did not 

exceed certain thresholds, no further refinement was necessary. 
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However, such refinements could result in higher modeled risks 

than those from the commenter’s Tier 2 modeling.

The EPA’s dispersion modeling of the case study facilities 

was actually performed with a greater degree of refinement than 

the EPRI analysis, and was consistent with EPA’s Guideline on 

Air Quality Models.296

In contrast to the approach used in the EPRI analysis, the 

EPA used:

1) 5 years of recent meteorological data from the weather 

station nearest to each facility, rather than one year of 

meteorological data. This is more representative of longterm (i.e., lifetime) exposures and risks.

2) Temporally-varying emissions based on continuous emissions 

monitoring data, rather than assuming a constant emission 

rate for each facility throughout the entire simulation.

3) Building downwash, where appropriate.

4) The latest version of AERMOD [version 11103]

The EPA’s assessment of the case study facilities for the 

proposed rule concluded that three coal-fired facilities and one 

oil-fired facility had estimated lifetime cancer risks greater 

than one in a million. For the final rule, revisions were made 

to the case studies based on comments received, and the results 

indicate that five coal-fired facilities and one oil-fired 

 

296 Appendix W to 40 CFR 51
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facility had estimated lifetime cancer risks greater than one in 

a million.

Regarding peer review, the risk assessment methodology used 

by EPA for the case studies was consistent with the method that 

EPA uses for assessments performed for Risk and Technology 

Review rulemakings, which underwent peer review by the Science 

Advisory Board in 2009.297 The SAB issued its peer review report 

in May 2010. The report generally endorsed the risk assessment 

methodologies used in the program. In addition, in July 2011, 

the EPA completed a letter peer review of the methods used to 

develop inhalation cancer risk estimates for Cr and Ni 

compounds.

f. Ecosystem Impacts from HAP

Comment: Two commenters assert that EPA is not justified in 

regulating acid gases based on concern about the potential that 

acid gases contribute to ecosystem acidification rather than 

concerns about hazards to public health. The commenters further 

claim that HCl’s contribution to ecosystem acidification is de 

minimis. The commenters point out that EPA acknowledges 

uncertainty in quantification of acidification and EPA relies on 

recently published research298 that is irrelevant to the question 

 

297 U.S. EPA-SAB, 2010. 

298 Evans, Chris D., Don T. Monteith, David Fowler, J. Neil Cape, 

and Susan Brayshaw. 2011. “Hydrochloric Acid: An Overlooked 

Driver of Environmental Change.” Environmental Science & 
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since it is based on research conducted in the peat bog 

ecosystem in the United Kingdom. Another commenter calls 

attention to several new studies published in a special issue of 

the journal Ecotoxicology devoted to the effects of MeHg on 

wildlife.

Response: Although EPA agrees that quantification of 

acidification effects has remaining uncertainty, the science and 

methodology has progressed in recent years. Based on recent peer 

reviewed research including Evans et al.,299 acid gases can 

significantly contribute to acidification. The EPA published a 

comprehensive risk assessment of acidification effects of 

nitrogen and sulfur deposition300 and a policy assessment.301

Given the extent and importance of the sensitive ecosystems 

evaluated in the review of nitrogen and sulfur deposition any 

 

Technology 45 (5), 1887-1894.

299 Id.

300 U.S. Environmental Protection Agency (U.S. EPA). 2009. Risk 

and Exposure Assessment for Review of the Secondary National 

Ambient Air Quality Standards for Oxides of Nitrogen and Oxides 

of Sulfur (Final). EPA-452/R-09-008a. Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. September. 

Available on the Internet at 

<http://www.epa.gov/ttn/naaqs/standards/no2so2sec/data/NOxSOxREA

Sep2009MainContent.pdf>.

301 U.S. Environmental Protection Agency (U.S. EPA). 2011d. 

Policy Assessment for the Review of the Secondary National 

Ambient Air Quality Standards for Oxides of Nitrogen and Oxides 

of Sulfur. EPA-452/R-11-005a. Office of Air Quality Planning and 

Standards, Research Triangle Park, NC. February. Available on 

the Internet at 

<http://www.epa.gov/ttnnaaqs/standards/no2so2sec/data/20110204pa

main.pdf>.
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substance that contributes to further acidification must be 

considered to be affecting the public welfare. The EPA disagrees 

that the peer reviewed study mentioned by commenter by Evans et 

al. (2011) is not relevant to U.S. ecosystems. The paper 

presents evidence that show 1) that HCl is highly mobile in the 

environment, transferring acidity easily through soils and 

water, 2) that HCl can transport longer distances than 

previously thought (given its presence in remote ecosystems, and 

3) that it can be a larger driver of acidification than 

previously thought. The fact that this study took place in the 

U.K. is itself irrelevant. The chemical interactions of HCl in 

water are the same the world over and sensitive ecosystems exist 

in the U.S. as well as in Europe as illustrated in the 

ecological risk assessment302 for NOX and SOX. Furthermore, the 

commenter is factually incorrect that EPA is justifying that it 

is appropriate and necessary to regulate HAP emissions from EGUs 

based on this one study. The EPA agrees with the commenter that 

Hg exposure in wildlife is responsible for various adverse 

health effects in many species across the U.S. and recognizes 

that research is ongoing in this area. As discussed in the 

preamble to the proposed rule, the EPA agrees that there are 

potential environmental risks from exposures of ecosystems 

through Hg and non-Hg HAP deposition. The EPA cited relevant 

 

302 U.S. EPA, 2009.
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articles from the special edition of Ecotoxicology303 mentioned 

by the commenter in the ecosystem effects section on Chapter 5 

of the RIA for this rule, which is available in the docket.

G. EPA Affirms the Finding that it is Appropriate and Necessary 

to Regulate EGUs to Address Public Health and Environmental 

Hazards Associated with Emissions of Hg and Non-Hg HAP from EGUs

In response to peer reviews of both the Hg and non-Hg HAP 

risk analyses, and taking into account public comments, the EPA

conducted revised analyses of the risks associated with 

emissions of Hg and non-Hg HAP from U.S. EGUs. These revised 

analyses demonstrated that the risk results reported in the 

preamble to the proposed rule are robust to revisions in 

response to the peer reviews and public comments.

Specifically, the revised Hg Risk TSD shows that up to 29 

percent of modeled watersheds have populations potentially atrisk from exposure to Hg from U.S. EGUs.304 This 29 percent of 

watersheds with populations potentially at-risk includes up to 

10 percent of modeled watersheds where deposition from U.S. EGUs 

alone leads to potential exposures that exceed the MeHg RfD, and 

up to 24 percent of modeled watersheds where total potential 

exposures to MeHg exceed the RfD and U.S. EGUs contribute at 

 

303 Ecotoxicology 17:83-91, 2008

304 This corresponds to 28 percent of modeled watersheds with 

populations potentially at-risk in the analysis reported in the 

preamble to the proposed rule.
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least 5 percent to Hg deposition. Each of these results

independently supports our conclusion that U.S. EGUs pose 

hazards to public health. 

In the preamble to the proposed rule and in the 2000 

finding, the EPA explained at length the serious nature of the 

health effects associated with Hg exposures, and the persistent 

nature of Hg in the environment. Congress specifically 

recognized the significant impacts of persistent bioaccumulative 

pollutants, like Hg, when it enacted section 112(c)(6), which 

requires the EPA to subject source categories listed pursuant to

that section to MACT standards. Congress also required certain 

studies be conducted under CAA section 112(n) regarding the 

health effects of Hg. The EPA interprets CAA section 112(n)(1), 

with regard to Hg, as intended to protect the public, including 

sensitive populations, against exposures to Hg from EGUs that 

would exceed the level determined by the EPA to be without 

appreciable risk, e.g., exposures that are above the RfD for 

methylmercury (MeHg), or would contribute additional risk in 

areas where Hg exposures exceed the RfD due to contributions 

from all sources of Hg. Our recent technical analyses show that 

98 percent of the watersheds for which we had fish tissue data 

have total Hg deposition such that potential exposures exceed 

the MeHg RfD, above which there is an increased risk of adverse 
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effects on human health. In these watersheds, any reductions in 

exposures to Hg will reduce risk, and thus the incremental 

contribution to Hg exposure from any individual source or group 

of sources, such as EGUs, may reasonably be anticipated to cause 

additional risk.

As we have explained, in calculating the estimates

described above, the EPA has used peer-reviewed methods, and 

focused on populations likely to be at higher risk of exposure 

to Hg from U.S. EGUs, e.g., female subsistence fishing 

populations consuming at the 99th percentile fish consumption 

rate. The EPA did not, however, use the most conservative 

assumptions that would lead to upper bound risk estimates. As 

discussed above and in the revised Hg Risk TSD, we did not use 

the highest fish tissue cooking loss adjustment factor that was 

reported in the literature, which, had we done so, would have 

increased the estimates of Hg exposure substantially. Thus, we 

believe our analysis could understate risk to the most exposed 

individual, noting that we have focused on the 99th percentile 

consumption rate in our estimates.

Further, we were able to assess potential Hg exposures in 

only a small subset of generally representative watersheds in 

the U.S. because our analysis was necessarily premised on those 

water bodies for which we had fish tissue Hg samples.
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Specifically, we analyzed 3,141 of the approximately 88,000 

watersheds in the United States. This limited set of watersheds 

excludes several of the watersheds with the highest U.S. EGU 

attributable deposition, and may also not have included 

watersheds with the highest sensitivity to Hg deposition, e.g., 

the highest methylation rates (see above). Nevertheless, our 

analysis of the subset of watersheds we examined demonstrates 

that almost one third of the watersheds are estimated to have Hg 

deposition attributable to U.S. EGUs that contributes to 

potential exposures above the MeHg RfD. The SAB confirmed that 

the subset of watersheds we examined is sufficient.

Considering these points and the information on Hg in the 

record, the EPA believes that 10 percent of watersheds with 

populations at risk due to U.S. EGU emissions alone is 

unacceptable, as is 24 percent of watersheds with populations at 

risk due to U.S. EGU contributions in conjunction with total 

deposition from other sources. Taking into account the

percentage of watersheds at risk, and the potential for even 

higher percentages to be at risk using more conservative risk 

assumptions and a more complete coverage of high U.S. EGU Hg 

deposition watersheds, the EPA concludes that Hg emissions from 

U.S. EGUs pose a hazard to public health.
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Given these findings, and considering that 1) the revised 

risk analysis showed the percent of modeled watersheds with 

populations potentially at-risk increased from 28 to 29 percent, 

and 2) the revised analysis includes 36 percent more watersheds, 

which significantly expands the coverage in several states, we 

conclude that the finding that emissions of Hg from U.S. EGUs 

pose a hazard to public health is confirmed by the nationalscale revised Hg Risk TSD. As a result, we conclude that it 

remains appropriate to regulate Hg emissions from U.S. EGUs 

because those Hg emissions pose a hazard to public health. 

With regards to the revised non-Hg inhalation case studies, 

the highest estimated individual lifetime cancer risk for the 

one case study facility (out of 16) with oil-fired EGUs is 

estimated to be 20 in a million, driven by Ni emissions. For the 

facilities with coal-fired EGUs, there were five (out of 16) 

with maximum individual cancer risks greater than one in a 

million (the highest was five in a million), four of which were 

driven by emissions of Cr(VI), and one of which was driven by 

emissions of Ni. Therefore, a total of six facilities exceed the 

criterion for EGUs to be regulated under CAA section 112. There 

were also two facilities with coal-fired EGUs with maximum 

individual cancer risks at one in a million. In the preamble to 

the proposed rule, we reported that the maximum individual 
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lifetime cancer risk for the one facility with oil-fired EGUs 

was estimated to be 10 in a million, and that there were 3 coalfired EGU facilities with maximum individual cancer risks 

greater than 1 in a million (the highest was 8 in a million), 

and 1 coal-fired EGU facility with maximum individual cancer 

risks equal to 1 in a million. Given that 1) the lifetime cancer 

risk for the oil-fired EGU facility has increased from 10 to 20 

in a million, 2) the number of coal-fired EGU facilities with 

cancer risks greater than 1 in a million has increased from 3 to 

5, and 3) the highest risk coal-fired facility still has cancer 

risks of 5 in a million, which is above the 1 in a million 

benchmark, we conclude that the finding that emissions of non-Hg 

HAP from U.S. EGUs pose a hazard to public health is confirmed 

by the revised non-Hg risk inhalation case studies.

Moreover, some HAP emissions from U.S. EGUs contribute to 

adverse ecosystem effects. While we did not do new analyses on 

these topics, we reiterate that 1) Hg emissions from U.S. EGUs 

pose a hazard to the environment, contributing to adverse 

impacts on fish-eating birds and mammals, 2) Hg is a persistent 

bioaccumulative environmental contaminant, and as a result, 

failing to control Hg emissions from U.S. EGU sources will 

result in long-term environmental loadings of Hg, above and 

beyond those loadings caused by immediate deposition of Hg 
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within the U.S.; controlling Hg emissions from U.S. EGUs helps 

to reduce the potential for environmental hazard from Hg now and 

in the future, and 4) it is appropriate to regulate those HAP 

which are not known to cause cancer but are known to contribute 

to chronic non-cancer toxicity and environmental degradation, 

such as the acid gases. In addition, we have identified 

effective controls available to reduce Hg and non-Hg HAP 

emissions.

In summary, we confirm the findings that Hg and non-Hg HAP 

emissions from U.S. EGUs each pose hazards to public health and 

that it remains appropriate to regulate U.S. EGUs under CAA 

section 112 for those reasons. We also conclude that it remains 

appropriate to regulate EGUs under CAA section 112 because of the 

magnitude of Hg and non-Hg emissions and the environmental 

effects of Hg and some non-Hg emissions, each of which standing 

alone, supports the appropriate finding. The availability of 

controls to reduce HAP emissions from EGUs only further supports 

the appropriate finding.

Our revised analyses still show that in 2016 after 

implementation of other provisions of the CAA, HAP emissions 

from U.S. EGUs are reasonably anticipated to pose hazards to 

public health; therefore, it is necessary to regulate EGUs under 

CAA section 112. Moreover, HAP emissions from U.S. EGUs are 
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expected to continue to contribute to adverse ecosystem effects. 

In addition, based on evaluation of the regulations required by 

the CAA, including the recent CSAPR, it is necessary to regulate 

U.S. EGUs under CAA section 112 because the only way to ensure 

permanent reductions in HAP emissions from U.S. EGUs and the 

associated risks to public health and the environment is through 

standards set under CAA section 112. While CSAPR is projected to 

achieve some Hg reductions due to co-control of Hg provided by 

controls put in place to achieve required reductions in SO2

emissions, the results of the revised Hg Risk TSD indicate that 

an unacceptable percentage of modeled watersheds have populations 

potentially at-risk from U.S. EGU-attributable Hg deposition 

would remain after implementation of CSAPR. While we modeled 

slightly higher Hg emissions from U.S. EGUs (i.e., 29 tons of Hg) 

in our risk analysis compared to the most recent estimate of 27 

tons, we do not believe this 2 ton difference would substantially 

change our finding that Hg emissions from U.S. EGUs pose a hazard 

to public health or the Hg risks reported in the preamble to the 

proposed rule, as this represents less than a 10 percent 

reduction in Hg emissions. In addition, the actual reductions in 

Hg that will occur due to application of controls to meet the SO2

emissions requirements of CSAPR may differ from those projected 

to occur, due to differences in the technologies that individual 
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EGU sources choose to install. The only way to ensure reductions 

in Hg, including those modeled as resulting from the CSAPR, is to 

directly regulate Hg emissions under CAA section 112.

In summary, we confirm the findings that it is necessary to 

regulate HAP emissions from U.S. EGUs because 1) the nationalscale Hg Risk TSD shows that the hazards to public health posed

by Hg emissions from U.S. EGUs will not be addressed through 

imposition of the CAA, 2) we cannot be certain that the 

identified cancer risks attributable to U.S. EGUs will be 

addressed through imposition of the requirements of the CAA, 3) 

the environmental hazards posed by acidification will not be 

fully addressed through imposition of the CAA, 4) regulation 

under CAA section 112 is the only way to ensure that all HAP 

emissions reductions that have been achieved since 2005 remain 

permanent, and 5) direct control of Hg emissions affecting U.S. 

deposition is only possible through regulation of U.S. emissions 

as we are unable to control global emissions directly. All of 

these findings independently support a finding that it is 

necessary to regulate U.S. EGUs under CAA section 112. 

Based on these findings, the Agency affirms its finding that 

it remains appropriate and necessary to regulate coal- and oilfired EGUs under CAA section 112, and maintains that the 

inclusion of coal- and oil-fired EGUs on the CAA section 112(c) 
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list of source categories regulated under CAA section 112 remains 

valid.

IV. Denial of Delisting Petition

During the comment period on the proposed rule, UARG 

submitted a petition pursuant to CAA section 112(c)(9), asking 

the Agency to delete a portion of the EGU source category from 

the list of source categories to be regulated under CAA section 

112. Specifically, UARG asks that EPA delist coal-fired EGUs 

from the CAA section 112(c) source category list. A copy of 

UARG’s petition has been placed in the docket for today’s 

rulemaking, along with the analysis conducted by EPRI that UARG 

uses to support its petition (hereinafter referred to as UARG’s 

analysis). In support of its petition, UARG asserts that: 1) no 

coal-fired EGU or group of coal-fired EGUs will emit HAP in 

amounts that will cause a lifetime cancer risk greater than one 

in one million; and 2) no coal-fired EGU or group of coal-fired 

EGUs will emit non-carcinogenic HAP in amounts that will exceed 

a level which is adequate to protect public health with an ample 

margin of safety or cause adverse environmental effects. We 

disagree with UARG’s assertions and for the reasons set forth 

below are denying UARG’s petition to delist coal-fired EGUs from 

the section 112(c) source category list.

A. Requirements of CAA section 112(c)(9)
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CAA section 112(c)(9)(B) provides that “[t]he Administrator 

may delete any source category” from the section 112(c) source 

category list if the Agency determines that: (i) for HAP that 

may cause cancer in humans, “no source in the category (or group 

of sources in the case of area sources) emits such hazardous air 

pollutants in quantities which may cause a lifetime risk of 

cancer greater than one in one million to the individual in the 

population who is most exposed to emissions of such pollutants 

from the source (or group of sources in the case of area 

sources)”; and (ii) for HAP that may result in human health 

effects other than cancer or adverse environmental effects, “a 

determination that emissions from no source in the category or 

subcategory concerned (or group of sources in the case of area 

sources) exceed a level which is adequate to protect public 

health with an ample margin of safety and no adverse 

environmental effect will result from emissions from any 

source.” 

The EPA has the discretion to delete a source category 

under CAA section 112(c)(9)(B), but only if EPA concludes that 

the relevant requirements of CAA section 112(c)(9)(B) have been 

met. HAP emissions from EGUs present both cancer risks, which 

implicate the requirements of CAA section 112(c)(9)(B)(i), and 

non-cancer human health effects or adverse environmental 
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effects, which implicate the requirements of CAA section 

112(c)(9)(B)(ii). As such, UARG bears the burden of 

demonstrating that the requirements of both clauses are met.

B. Rationale for Denying UARG’s Delisting Petition

The EPA is denying UARG’s petition to delist EGUs from the 

CAA section 112(c) source category list. UARG improperly seeks 

to delist a portion of a CAA section 112(c) listed source 

category that emits carcinogens, which is contrary to the plain 

language of CAA section 112(c)(9). Even setting aside this 

fundamental defect, UARG has failed to meet the requirements of 

CAA section 112(c)(9)(B).

1. UARG’s Attempt to Delist a Portion of a Listed Source 

Category Conflicts with D.C. Circuit Precedent

In December 2000, the EPA listed coal- and oil-fired EGUs 

as a single source category. UARG asks the Agency to delist a 

portion of that listed source category: coal-fired EGUs. UARG’s 

request conflicts, however, with D.C. Circuit precedent, which 

provides that for categories, like EGUs, that pose cancer risks, 

the EPA may not delist a portion of a source category. NRDC v. 

U.S. EPA, 489 F.3d 1364 (D.C. Cir. 2007). Specifically, in NRDC, 

the D.C. Circuit held that the Agency’s attempt to delist a 

“low-risk” subcategory was “contrary to the plain language of 

the statute,” and that the statute only authorized the agency to 
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remove source categories pursuant to section 112(c)(9). Id. at 

1373 (“Because EPA’s interpretation of Section 112(c)(9) as 

allowing it to exempt the risk-based subcategory is contrary to 

the plain language of the statute, the EPA’s interpretation 

fails at Chevron step one.”).

UARG’s request is indistinguishable from the situation 

before the court in NRDC. UARG does not seek to delist coal-and 

oil-fired EGUs, which is the source category that EPA listed, 

but rather a portion of that category. UARG also does not 

dispute that coal-fired EGUs emit carcinogenic HAP. Because 

UARG’s request to delist is contrary to the plain language of 

CAA section 112(c)(9)(B) and NRDC, we are denying the delisting 

petition.

2. Even assuming, for the sake of argument, that EPA could 

delist a portion of a source category, UARG has failed to meet 

the requirements of CAA section 112(c)(9).

Even assuming, for the sake of argument, that EPA could 

delist a portion of a source category that emits carcinogens, 

which it cannot, UARG has failed to demonstrate that the 

requirements for delisting in CAA section 112(c)(9)(i) and (ii) 

have been met. UARG contends that it used EPA’s models and 

approaches, as well as the most recent data. We have carefully 

reviewed UARG’s analyses, however, and found certain flaws that 
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we believe bias their risk results low. Specifically, we 

identified flaws in emissions estimation. UARG developed 

estimates for all EGU facilities using data which pre-date the 

2010 ICR emissions measurement data that EPA obtained to support 

this rule. UARG also relied upon an emissions equation developed 

by EPRI and DOE to develop its metal emissions estimates. With 

regard to that approach, the EPA analysis of the ICR data has 

found that the regression approach is not a good predictor of 

actual EGU emissions. Furthermore, we found fault with their use 

of the geometric mean and their outlier analysis for computing

emission factors. The EPA analysis has found that the geometric 

mean approach underpredicts actual emissions by an average of 

more than seventy percent. This had an especially large impact 

on the arsenic, chromium, and nickel emissions estimates. These 

and other issues are explained in further detail in the response 

to comments document. As a result, we believe the resulting risk 

estimates in UARG’s analysis are biased low. In addition, we 

note that there are dispersion model refinements that are not 

included in the UARG analyses, but were included in EPA’s 

analysis. For example, for the dispersion modeling of the 16 

non-Hg case studies, the EPA considered building downwash and 

used time-varying emissions, neither of which were used in 
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UARG’s analysis. These factors could also bias the UARG risk 

estimates low.

However, even taking UARG’s analysis at face value and 

accepting, for arguments’ sake, their assumptions and emissions 

estimates, UARG’s own data supports denial of the petition 

because UARG itself identifies a maximum individual cancer risk 

exceeding 1 in a million, which is the statutory threshold in 

CAA section 112(c)(9)(B)(i). Specifically, UARG’s multi-pathway 

model plant ingestion risk analysis concluded that adult anglers 

would face cancer risks of 4 in a million. For this reason 

alone, the petition should be denied.

UARG dismisses the 4 in a million cancer result, arguing 

that the refined model plant multipathway risk assessment that 

it conducted is “overly conservative.” UARG conducted its multipathway risk analysis to evaluate the risks associated with 

ingesting persistent and bioaccumulative HAP which are emitted 

into the atmosphere and subsequently deposit into the 

environment and bioaccumulate in animals which are eventually 

consumed as food. Instead of conducting this multipathway 

analysis for each EGU facility, UARG instead analyzed multipathway risks by evaluating a single model plant. Nothing in the 

record indicates, however, that UARG’s model plant represents 

the worst-case scenario for cancer human health risks from any 
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EGU. Indeed, although UARG claims in its petition that the site 

selected for its case study is “likely as close to a worst-case 

scenario as is possible given the numerous variables associated 

with ingestion pathway risks” (UARG petition at 12), the 

supporting documentation for that case study specifically 

acknowledges that its fictional model plant scenario “is not 

intended to represent the risk due to emissions from an actual 

plant or the highest level of risk that could be associated with 

a coal-fired power plant at any location” (EPRI at 1). The 

statute requires that no source in the category may cause a 

lifetime cancer risk greater than one in one million to the most 

exposed individual, and UARG has failed to make this showing.

UARG has neither modeled multi-pathway risks for a worst-case 

model facility, nor evaluated the multipathway risks associated 

with each individual EGU facility. Accordingly, UARG has not 

made the demonstration required by CAA section 112(c)(9)(B)(i).

But, even focusing on the multi-pathway risk analysis that UARG 

did conduct, which admittedly does not represent a worst-case 

facility, UARG’s analysis still shows cancer risks greater than 

one in a million. Accordingly, UARG’s petition must be denied. 

Although it is not necessary to reach the requirements of 

CAA section 112(c)(9)(B)(ii) that address non-cancer human 

health risks, we note that UARG has also failed to show that 
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“emissions from no source in the category...exceed a level which 

is adequate to protect public health with an ample margin of 

safety.” Again, even accepting, for argument’s sake, the 

conclusions in UARG’s analysis, UARG only evaluated the noncancer inhalation risks associated with each EGU facility. It 

did not conduct a similar analysis to assess multipathway risks 

for each EGU facility. Instead, it conducted a model plant 

analysis and admits that such model plant does not represent the 

worst-case scenario for noncancer human health risks from any 

EGU. Thus, the analysis fails to fully characterize noncancer 

multipathway risks for the source category, and UARG’s petition 

must be denied on this basis as well.

Finally, UARG failed to meet its burden of showing that “no 

adverse environmental effect will result from emissions from any 

source” pursuant to CAA section 112(c)(9)(B)(ii). UARG analyzed 

environmental effects only in conjunction with its model plant.

Because UARG’s model plant does not represent the worst-case 

scenario for environmental effects, UARG’s analysis falls short 

and fails to characterize fully the potential environmental 

impacts, and UARG’s petition must be denied.

For all of these reasons, the EPA denies UARG’s petition to 

delist coal-fired EGUs from the CAA section 112(c) source 

category list.
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C. EPA’s technical analyses for the appropriate and necessary 

finding provide further support for the conclusion that coalfired EGUs should remain a listed source category

The EPA reasonably concluded in December 2000, based on the

information available to the Agency at that time, that it was 

appropriate and necessary to regulate coal- and oil-fired EGUs 

under CAA section 112 and added such units to the list of source 

categories subject to regulation under CAA section 112(d). As 

discussed in section III above, the EPA conducted additional, 

extensive technical analyses based on recent data that confirm 

it remains appropriate and necessary to regulate HAP from coaland oil-fired EGUs, because such EGUs continue to pose hazards 

to public health. HAP emissions from coal-and oil-fired EGUs 

also continue to cause adverse environmental effects. UARG 

advances several arguments, challenging the analyses the Agency 

completed in support of the proposed rule. We address those 

arguments in section III above. The Agency’s analyses supporting 

the appropriate and necessary finding confirm that EGUs cannot 

be delisted pursuant to CAA section 112(c)(9).

Specifically, as explained further in section III above, 

the EPA analyzed non-Hg inhalation risks from 16 EGU facility 

case studies, including both coal- and oil-fired EGUs, as part 

of its technical analyses supporting the appropriate and 
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necessary finding. That analysis demonstrates that there are 6 

EGU facilities (of the 16 that we analyzed) with cancer risks 

exceeding one in one million. These cancer risk levels exceed 

the delisting criteria set forth in CAA section 112(c)(9)(B)(i), 

and confirm that EGUs must remain a listed source category. As 

explained above, some commenters assert that EPA’s analysis of 

non-Hg inhalation risks from EGUs conducted in support of the 

proposal for this rulemaking overstated emissions from, and 

risks associated with, EGUs. These commenters argue that the 

analysis supporting UARG’s petition more appropriately assesses 

EGU risk. The EPA disagrees with these comments and addresses 

these comments in section III above.

Significantly, the EPA based its analysis of 16 case study 

EGUs directly on the 2010 emissions test data from EGUs obtained 

through the ICR. The EPA’s 16 case study analysis used emissions 

data either taken directly from the 2010 emissions test data, or 

derived using emissions factors based on the 2010 data for 

similar EGU units. The EPA also included dispersion model 

refinements in its final case studies, as noted above. Further, 

the EPA re-analyzed the 16 case studies that we conducted for 

the proposal and revised those analyses consistent with new nonHg HAP emissions data and corrected stack parameters provided by 

commenters (including UARG) during the comment period on the 
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proposed rule. The EPA received revised information concerning 

emissions tests, stack heights and stack diameters for some of 

the case study EGU facilities. The EPA incorporated all of these 

corrections into our analysis and then re-analyzed the risks for 

the 16 case study facilities. When completed, the EPA determined 

that the corrections incorporated into the reanalysis had little 

effect on the overall results. In the final rule, the EPA

concludes that the maximum individual inhalation cancer risks 

for 6 out of the 16 case study EGU facilities are greater than 1 

in a million. These cancer risk levels confirm that EGUs do not 

satisfy the delisting criterion of CAA section 112(c)(9)(B)(i) 

and thus should remain a listed source category. 

The EPA’s national-scale Hg Risk TSD supporting the 

appropriate and necessary finding also confirm that Hg emissions 

from coal- and oil-fired US EGUs are reasonably anticipated to 

pose a hazard to public health. As discussed in section III 

above, the EPA interprets CAA section 112(n)(1), with regard to 

mercury, as intended to protect the public, including sensitive 

populations, against exposures to Hg from EGUs that would exceed 

the level determined by EPA to be without appreciable risk, 

e.g., exposures that are above the RfD for methylmercury (MeHg), 

or would contribute additional risk in areas where Hg exposures 

exceed the RfD due to contributions from all sources of Hg.
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In order to determine whether EGU Hg emissions pose a 

hazard to public health, the EPA conducted a national-scale Hg

Risk TSD focused on populations with high levels of self-caught 

freshwater fish consumption. The results of the Hg Risk TSD show 

that 98 percent of modeled watersheds have total exposures to 

MeHg that exceed the MeHg RfD, above which there is an increased 

risk of adverse effects on human health. In these watersheds, 

any reductions in exposures to Hg will reduce risk, and thus the 

incremental contribution to Hg exposure from any individual 

source or group of sources, such as EGUs, may reasonably be 

anticipated to cause additional risk. The Hg Risk TSD focused on 

those watersheds that either exceeded the RfD based on U.S. EGU 

attributable deposition alone, without considering other sources 

of deposition, or watersheds that exceed the RfD due to total Hg 

deposition and to which U.S. EGUs contributed at least 5 percent 

of the Hg deposition. The results of that analysis show that up 

to 29 percent of the modeled watersheds have populations that 

are potentially at-risk from exposure to Hg from U.S. EGUs, 

including up to 10 percent of modeled watersheds where 

deposition from U.S. EGUs alone leads to potential exposures 

that exceed the MeHg RfD, and up to 24 percent of modeled 

watersheds where total potential exposures to MeHg exceed the 

RfD and U.S. EGUs contribute at least 5 percent to Hg 
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deposition. This approach to assessing national risks from Hg 

deposition from EGUs was supported by the independent peer 

review conducted by the Science Advisory Board, as discussed 

fully in section III.

Finally, as discussed in section III, based on this 

assessment, the EPA has confirmed that Hg emitted from U.S. EGUs 

pose a hazard to public health and it is appropriate to regulate 

U.S. EGUs under CAA section 112. This determination and the 

confirmatory assessments support our conclusion that UARG’s 

delisting petition must be denied.

UARG attempts to dismiss the results of EPA’s nationalscale Hg Risk TSD, arguing that EPA cannot consider the risks 

posed by EGUs in conjunction with any other risks, including 

those from other source categories. Nothing in CAA section 

112(c)(9), however, provides that the Agency cannot consider 

background or emissions due to other sources. CAA section 

112(c)(9)(B)(ii) provides that “no source in the category or 

subcategory concerned (or group of sources in the case of area 

sources) exceed a level which is adequate to protect public 

health with an ample margin of safety and no adverse 

environmental effect will result from emissions from any 

source.” This language could be read to provide that the Agency 

consider only the risks associated with the source category at 
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issue, and ignore how those risks fit with real-world 

exposures.305 However, the language could also be read to provide 

that the Agency consider the cumulative effect of HAP emissions 

from the individual sources in the category in conjunction with 

the HAP emissions from other sources. The latter is a reasonable 

interpretation, especially when considering how the public is 

exposed to HAP emissions. Considering the individual sources in 

a source category in isolation treats the sources as if they 

exist in a vacuum, which does not mirror reality. Such an 

approach is particularly problematic for environmentally 

persistent HAP that bio-accumulate in the food chain, such as 

mercury.306

 

305 The same is true with respect to section 112(c)(9)(B)(i). 

306 In a prior rulemaking, EPA stated that the language in 

section 112(c)(9)(B)(ii) “does not direct EPA to extend its 

analysis to either emissions from other sources in other 

categories or subcategories or to non-attributable background 

concentrations.” 71 FR 8347 (Feb. 16, 2006). The preamble to 

that rule repeatedly states that the “focus” of the delisting 

determination in that rule was on emissions from sources in the 

category under review. See 71 FR 8346-47. The preamble went on 

to compare section 112(c)(9)(B) to section 112(f)(2)(A) in a way 

that suggested that EPA can consider risks presented by sources 

other than the subject source category under section 112(f)(2), 

but not under section 112(c)(9). We do not believe the language 

of section 112(c)(9) compels any different treatment. The 

section 112(f) analysis occurs after a source category has 

already complied with section 112(d) standards, whereas, 

potential delistings under section 112(c)(9) may involve source 

categories unregulated by section 112. A delisting decision is 

significant in that the category that is delisted will no longer 

be subject to HAP regulation under the Act. It is difficult to 

justify why we would examine risks from other sources under 
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Here, the record demonstrates that 98 percent of the 

watersheds EPA modeled have total exposures to MeHg that exceed 

the MeHg RfD, above which there is increased risk of adverse 

effects on human health, especially on the developing nervous 

systems of children during gestation. EGUs remain one of the 

largest unregulated sources of Hg emissions, and those emissions 

continue to contribute to Hg exposures and risk. UARG seeks to 

ignore the fact that exposures above the RfD exist in almost 

every watershed we modeled, and instead focuses on the 

contribution provided solely by EGUs. The EPA did as UARG asked 

and found that up to 10 percent of modeled watersheds where 

deposition from U.S. EGUs alone leads to potential exposures 

that exceed the MeHg RfD. Thus, even focusing on EGU emissions 

in a vacuum, which we do not believe is appropriate or required 

under CAA section 112(c)(9), we still found that up to 10 

percent of the watersheds exceed the RfD due to EGU emissions 

even before taking into account the numerous other sources of Hg 

deposition, and we believe this to be an unacceptable percentage 

of watersheds above the RfD. Due to the persistent, 

bioacccumulative nature of Hg, among other factors, we believe 

it is appropriate to consider the combined impact of Hg 

emissions from EGUs and other sources of Hg. Thus, we also 

 

section 112(f), but not under section 112(c)(9), where Congress 

established such a specific test for delisting. 
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considered the 24 percent of modeled watersheds where, even 

though U.S. EGU emissions alone are not enough to cause 

exposures that exceed the RfD, those emissions contribute at 

least 5 percent of total exposures to MeHg that exceed the RfD.

The combined total of 29 percent of modeled watersheds where 

U.S. EGUs cause or contribute to MeHg exposures above the RfD is 

clearly unacceptable and thus the UARG petition to delist must 

be denied.

Thus, the technical analyses the Agency conducted in 

support of the appropriate and necessary finding confirm that 

EGUs should remain a listed source category.

V. Summary of this Final NESHAP

This section summarizes the requirements of the final EGU 

NESHAP. Section VI below summarizes the significant changes to 

this final rule following proposal.

A. What is the source category regulated by this final rule?

This final rule affects coal- and oil-fired EGUs.

B. What is the affected source?

An existing affected source under this final rule is the 

collection of coal- or oil-fired EGUs in a subcategory within a 

single contiguous area and under common control. A new affected 

source is each coal- or oil-fired EGU for which construction or 

reconstruction began after May 3, 2011.
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CAA section 112(a)(8) defines an EGU as:

a fossil fuel-fired combustion unit of more than 25 

megawatts 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 megawatts electrical output to any utility power 

distribution system for sale shall be considered an 

electric utility steam generating unit.

If an EGU burns coal (either as a primary fuel or as a 

supplementary fuel) or any combination of coal with another fuel 

(except for solid waste as noted below) where the coal accounts 

for more than 10.0 percent of the average annual heat input 

during any 3 consecutive calendar years or for more than 15.0 

percent of the annual heat input during any one calendar year

after the applicable compliance date, 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 (except 

solid waste as noted below) where the oil accounts for more than 

10.0 percent of the average annual heat input during any 3 

consecutive calendar years or for more than 15.0 percent of the 

annual heat input during any one calendar year after the 
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applicable compliance date, the unit is considered to be oilfired under this final rule.

As noted below, the EPA is finalizing in this rule a 

definition to determine whether the combustion unit is “fossil 

fuel fired” such that it is considered an EGU as defined in CAA 

section 112(a)(8) and, thus, potentially subject to this final 

rule. In addition, using the construct of the definition of 

“oil-fired” from the ARP, we are finalizing in this rule a 

requirement that the unit fire coal or oil (or natural gas), or 

any combination thereof, for more than 10.0 percent of the 

average annual heat input during any 3 consecutive calendar 

years or for more than 15.0 percent of the annual heat input 

during any one calendar year to be considered a “fossil fuelfired” EGU as defined in CAA section 112(a)(8). However, if a 

new or existing EGU is not coal- or oil-fired, and the unit 

burns natural gas exclusively or burns natural gas in 

combination with another fuel where the natural gas constitutes 

10 percent or more of the average annual heat input during any 3 

calendar years or 15 percent or more of the annual heat input 

during any 1 calendar year, the unit is considered to be natural 

gas-fired EGU and not subject to this final rule. As discussed 

later, we believe that this definition will address those 

situations where an EGU co-fires limited amounts of either coal 
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or oil with natural gas or other non-fossil fuels (e.g., 

biomass).

If an EGU combusts solid waste, standards issued pursuant 

to CAA section 129 apply to that EGU, rather than this final 

rule.

C. What are the pollutants regulated by this final rule?

For coal-fired EGUs, this final rule regulates HCl as a 

surrogate for acid gas HAP, with an alternate of SO2 as a 

surrogate for acid gas HAP for coal-fired EGUs with FGD systems 

installed and operational; filterable PM as a surrogate for nonmercury HAP metals, with total non-mercury HAP metals and 

individual non-mercury HAP metals as alternative equivalent 

standards; Hg; and organic HAP. For oil-fired EGUs, this final 

rule regulates HCl and HF; filterable PM as a surrogate for 

total HAP metals, with individual HAP metals as alternative 

equivalent standards; and organic HAP.

D. What emission limits and work practice standards must I meet

and what are the subcategories in the final rule?

We are finalizing the emission limitations presented in 

Tables 3 and 4 of this preamble. Within the two major 

subcategories of “coal” and “oil,” emission limitations were 

developed for new and existing sources for seven subcategories, 

two for coal-fired EGUs, one for IGCC EGUs burning synthetic gas 
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derived from coal- and/or solid oil-derived fuel, one for solid 

oil-derived fuel-fired EGUs, and four for liquid oil-fired EGUs, 

as described in more detail below. The limited-use liquid oilfired subcategory, discussed elsewhere in this preamble, is not 

presented in Table 3 because only work practice standards apply 

to this subcategory.

TABLE 3. EMISSION LIMITATIONS FOR COAL-FIRED AND SOLID OILDERIVED FUEL-FIRED EGUS

Subcategory Filterable 

particulate 

matter

Hydrogen 

chloride

Mercury

Existing - Unit 

not low rank 

virgin coal

3.0E-2

lb/MMBtu 

(3.0E-1

lb/MWh)

2.0E-3

lb/MMBtu

(2.0E-2 

lb/MWh)

1.2E0 lb/TBtu

(1.3E-2

lb/GWh)

Existing - Unit 

designed low 

rank virgin 

coal

3.0E-2 

lb/MMBtu 

(3.0E-1 

lb/MWh)

2.0E-3

lb/MMBtu

(2.0E-2

lb/MWh)

1.1E+1

lb/TBtu

(1.2E-1

lb/GWh)

4.0E0

lb/TBtua

(4.0E-2

lb/GWha)

Existing - IGCC 4.0E-2

lb/MMBtu 

(4.0E-1

lb/MWh)

5.0E-4

lb/MMBtu 

(5.0E-3

lb/MWh)

2.5E0 lb/TBtu

(3.0E-2

lb/GWh)

Existing –

Solid oilderived 

8.0E-3

lb/MMBtu

(9.0E-2

lb/MWh)

5.0E-3

lb/MMBtu 

(8.0E-2

lb/MWh)

2.0E-1

lb/TBtu 

(2.0E-3 

lb/GWh)

New - Unit not 

low rank virgin 

coal

7.0E-3 lb/MWh 4.0E-4 lb/MWh 2.0E-4 lb/GWh

New - Unit 

designed for 

low rank virgin 

coal

7.0E-3 lb/MWh 4.0E-4 lb/MWh 4.0E-2 lb/GWh

New – IGCC 7.0E-2 2.0E-3 3.0E-3
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lb/MWhb

9.0E-2

lb/MWhc

lb/MWhd lb/GWhe

New – Solid 

oil-derived 

2.0E-2 lb/MWh 4.0E-4 lb/MWh 2.0E-3 lb/GWh

Note: lb/MMBtu = pounds pollutant per million British thermal 

units fuel input

lb/TBtu = pounds pollutant per trillion British thermal units 

fuel input

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

(gross)

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

(gross)

a Beyond-the-floor limit as discussed elsewhere

b Duct burners on syngas; based on permit levels in comments 

received

c Duct burners on natural gas; based on permit levels in comments 

received

d Based on best-performing similar source

e Based on permit levels in comments received

TABLE 4. EMISSION LIMITATIONS FOR LIQUID OIL-FIRED EGUS

Subcategory Filterable 

particulate 

matter

Hydrogen 

chloride

Hydrogen 

fluoride

Existing – Liquid oilcontinental 3.0E-2

lb/MMBtu

(3.0E-1

lb/MWh)

2.0E-3 

lb/MMBtu

(1.0E-2 

lb/MWh)

4.0E-4

lb/MMBtu

(4.0E-3

lb/MWh)

Existing – Liquid oilnon-continental 3.0E-2

lb/MMBtu

(3.0E-1

lb/MWh)

2.0E-4

lb/MMBtu

(2.0E-3

lb/MWh)

6.0E-5

lb/MMBtu

(5.0E-4

lb/MWh)

New – Liquid oil -

continental

7.0E-2

lb/MWh

4.0E-4

lb/MWh

4.0E-4

lb/MWh

New – Liquid oil -

non-continental

2.0E-1

lb/MWh

2.0E-3

lb/MWh

5.0E-4

lb/MWh

We are also finalizing alternate equivalent emission 

standards (for certain subcategories) to the final surrogate 

standards in three areas: SO2 (for HCl), individual non-mercury

metals and total non-mercury metals (for filterable PM) from 
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coal- and solid oil-derived fuel-fired EGUs, and individual and 

total metals (for filterable PM) from oil-fired EGUs. The final

alternate emission limitations are provided in Tables 5 and 6 of 

this preamble.

TABLE 5. ALTERNATE EMISSION LIMITATIONS FOR EXISTING COAL- AND 

OIL-FIRED EGUS

Subcategory

/

Pollutant

Coalfired 

EGUs

IGCC Liquid 

oil, 

continen

tal 

Liquid 

oil, 

noncontinen

tal 

Solid 

oilderived

SO2 2.0E-1

lb/MMBtu 

(1.5E0

lb/MWh)

NA NA NA 3.0E-1

lb/MMBtu 

(2.0E0

lb/MWh)

Total nonmercury

metals

5.0E-5

lb/MMBtu

(5.0E-1

lb/GWh)

6.0E-5

lb/MMBtu

(5.0E-1

lb/GWh)

8.0E-4 

lb/MMBtu 

(8.0E-3 

lb/MWh)a

6.0E-4 

lb/MMBtu

(7.0E-3 

lb.MWh)a

4.0E-5

lb/MMBtu 

(6.0E-1

lb/GWh)

Antimony, 

Sb

8.0E-1

lb/TBtu

(8.0E-3

lb/GWh)

1.4E0

lb/TBtu

(2.0E-2 

lb/GWh)

1.3E+1

lb/TBtu

(2.0E-1

lb/GWh)

2.2E0

lb/TBtu

(2.0E-2

lb/GWh)

8.0E-1 

lb/TBtu

(8.0E-3 

lb/GWh)

Arsenic, As 1.1E0

lb/TBtu

(2.0E-2

lb/GWh)

1.5E0 

lb/TBtu

(2.0E-2

lb/GWh)

2.8E0

lb/TBtu

(3.0E-2

lb/GWh)

4.3E0

lb/TBtu

(8.0E-2

lb/GWh)

3.0E-1

lb/TBtu

(5.0E-3

lb/GWh)

Beryllium, 

Be

2.0E-1

lb/TBtu

(2.0E-3

lb/GWh)

1.0E-1 

lb/TBtu

(1.0E-3 

lb/GWh)

2.0E-1

lb/TBtu

(2.0E-3

lb/GWh)

6.0E-1

lb/TBtu

(3.0E-3

lb/GWh)

6.0E-2

lb/TBtu

(6.0E-4

lb/GWh)

Cadmium, Cd 3.0E-1

lb/TBtu

(3.0E-3

lb/GWh)

1.5E-1

lb/TBtu

(2.0E-3

lb/GWh)

3.0E-1

lb/TBtu

2.0E-3

lb/GWh)

3.0E-1

lb/TBtu

(3.0E-3

lb/GWh)

3.0E-1

lb/TBtu

(4.0E-3

lb/GWh)

Chromium, 

Cr

2.8E0

lb/TBtu

(3.0E-2

lb/GWh)

2.9E0

lb/TBtu

(3.0E-2

lb/GWh)

5.5E0

lb/TBtu

(6.0E-2

lb/GWh)

3.1E+1

lb/TBtu

(3.0E-1

lb/GWh)

8.0E-1

lb/TBtu

(2.0E-2

lb/GWh)

Cobalt, Co 8.0E-1

lb/TBtu

1.2E0 

lb/TBtu

2.1E+1

lb/TBtu

1.1E+2

lb/TBtu

1.1E0

lb/TBtu
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(8.0E-3

lb/GWh)

(2.0E-2 

lb/GWh)

(3.0E-1

lb/GWh)

(1.4E0 

lb/GWh)

(2.0E-2

lb/GWh)

Lead, Pb 1.2E0

lb/TBtu

(2.0E-2

lb/GWh)

1.9E+2

lb/MMBtu

(1.8E0

lb/MWh)

8.1E0

lb/TBtu

(8.0E-2

lb/GWh)

4.9E0

lb/TBtu

(8.0E-2

lb/GWh)

8.0E-1

lb/TBtu

(2.0E-2

lb/GWh)

Manganese, 

Mn

4.0E0

lb/TBtu

(5.0E-2

lb/GWh

2.5E0

lb/TBtu

(3.0E-2

lb/GWh)

2.2E+1

lb/TBtu

(3.0E-1

lb/GWh)

2.0E+1

lb/TBtu

(3.0E-1

lb/GWh)

2.3E0

lb/TBtu

(4.0E-2

lb/GWh)

Mercury, Hg NA NA 2.0E-1

lb/TBtu

(2.0E-3

lb/GWh)

4.0E-2

lb/TBtu 

(4.0E-4

lb/GWh)

NA

Nickel, Ni 3.5E0

lb/TBtu

(4.0E-2

lb/GWh)

6.5E0

lb/TBtu

(7.0E-2

lb/GWh)

1.1E+2

lb/TBtu

(1.1E0

lb/GWh)

4.7E+2

lb/TBtu

(4.1E0

lb/GWh)

9.0E0

lb/TBtu

(2.0E-1

lb/GWh)

Selenium, 

Se

5.0E0

lb/TBtu

(6.0E-2

lb/GWh)

2.2E+1

lb/TBtu

(3.0E-1

lb/GWh)

3.3E0

lb/TBtu

(4.0E-2

lb/GWh)

9.8E0

lb/TBtu

(2.0E-1

lb/GWh)

1.2E0

lb/TBtu

(2.0E-2

lb/GWh)

NA = Not applicable

a Includes Hg.

TABLE 6. ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OILFIRED EGUS

Subcategory

/

Pollutant

Coalfired 

EGUs

IGCCa Liquid 

oil, 

continen

tal, 

lb/GWh

Liquid 

oil, 

noncontinen

tal, 

lb/GWh

Solid 

oilderived

SO2 4.0E-1

lb/MWh

4.0E-1 

lb/MWh

NA NA 4.0E-1

lb/MWh

Total nonmercury 

metals

6.0E-2

lb/GWh

4.0E-1

lb/GWh

2.0E-4 

lb/MWhb

7.0E-3 

lb/MWhb

6.0E-1

lb/GWh

Antimony, 

Sb

8.0E-3

lb/GWh

2.0E-2

lb/GWh

1.0E-2 8.0E-3 8.0E-3 

lb/GWh

Arsenic, As 3.0E-3

lb/GWh

2.0E-2 

lb/GWh

3.0E-3 6.0E-2 3.0E-3

lb/GWh

Beryllium, 

Be

6.0E-4

lb/GWh

1.0E-3 

lb/GWh

5.0E-4 2.0E-3 6.0E-4 

lb/GWh

Cadmium, Cd 4.0E-4 2.0E-3 2.0E-4 2.0E-3 7.0E-4
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lb/GWh lb/GWh lb/GWh 

Chromium, 

Cr

7.0E-3

lb/GWh

4.0E-2

lb/GWh

2.0E-2 2.0E-2 6.0E-3

lb/GWh

Cobalt, Co 2.0E-3

lb/GWh

4.0E-3

lb/GWh

3.0E-2 3.0E-1 2.0E-3

lb/GWh

Lead, Pb 2.0E-3

lb/GWh

9.0E-3

lb/GWh

8.0E-3 3.0E-2 2.0E-2

lb/GWh

Mercury, Hg NA NA 1.0E-4 4.0E-4 2.0E-3 

lb/GWh

Manganese, 

Mn

4.0E-3

lb/GWh

2.0E-2

lb/GWh

2.0E-2 1.0E-1 7.0E-3

lb/GWh 

Nickel, Ni 4.0E-2

lb/GWh

7.0E-2

lb/GWh

9.0E-2 4.1E0 4.0E-2 

lb/GWh

Selenium, 

Se

6.0E-3

lb/GWh

3.0E-1

lb/GWh

2.0E-2 2.0E-2 6.0E-3 

lb/GWh

NA = Not applicable

a Based on best-performing similar source

b Includes Hg.

As noted elsewhere in this preamble, we are finalizing a 

requirement to use filterable PM as a surrogate for the nonmercury metallic HAP and HCl as a surrogate for the acid gas HAP 

for all subcategories of coal-fired EGUs and for the solid oil 

derived fuel-fired EGUs. For all liquid oil-fired EGUs, we are 

finalizing a requirement to use filterable PM as a surrogate for 

the total metallic HAP, and we are finalizing HCl and HF limits.

In addition, we are finalizing alternative standards for 

certain HAP for some subcategories. The alternative pollutants 

and subcategories are as follows: 1) SO2 as a surrogate to HCl 

for all subcategories with add-on FGD systems (except liquid 

oil-fired subcategories as there were no existing units from 

which to base an alternate SO2 limit); 2) individual non-mercury 

metallic HAP as an alternate to filterable PM for all 
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Page 345 of 1103

subcategories (except that it includes Hg for liquid oil-fired

subcategories); and 3) total non-mercury metallic HAP as an 

alternate to filterable PM for all subcategories (except that it 

includes Hg for liquid oil-fired subcategories). These 

alternative standards are discussed elsewhere in this preamble.

We are finalizing a beyond-the-floor standard for Hg only 

for all existing coal-fired units designed for low rank virgin 

coal based on the use of activated carbon injection (ACI) for Hg 

control, as described elsewhere in this preamble. The EPA has 

determined that this beyond-the-floor level is achievable after 

considering the relevant CAA section 112(d)(2) provisions.

As noted elsewhere in this preamble, we are also finalizing 

a compliance assurance option that would allow you to monitor

liquid oil fuel moisture to demonstrate that fuel moisture 

content is no greater than 1.0 percent. Provided that 

demonstration is made, you will not have to conduct additional 

testing and monitoring to demonstrate compliance with the HCl 

and HF emission limits for units in both liquid oil 

subcategories (i.e., continental and non-continental).

Pursuant to CAA section 112(h), we are finalizing a work 

practice standard for organic HAP, including emissions of 

dioxins and furans, for all subcategories of EGUs. The work 

practice standard being finalized requires the implementation of 
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periodic burner tune-up procedures described elsewhere in this 

preamble. We are finalizing work practice standards because the 

significant majority of data for measured organic HAP emissions 

from EGUs are below the detection levels of the EPA test 

methods, even when long duration (around 8 hour) test runs are 

considered. As such, we consider it impracticable to measure 

emissions from these units. As discussed at proposal, we believe 

the inaccuracy of a majority of measurements, coupled with the 

extended sampling times used, allow a work practice standard 

under CAA section 112(h) to apply to these HAP.307 We believe 

that a work practice standard will lead to a better 

environmental outcome than would be obtained through a 

requirement to measure a pollutant for which results may or may 

not be obtained. We believe that the work practice standard will 

result in actions being taken that will reduce emissions of 

these HAP.

In addition, as discussed below, we are creating a 

subcategory for limited use liquid oil-fired electric utility 

steam generating unit with an annual capacity factor of less 

than 8 percent of its maximum or nameplate heat input and we are 

establishing work practice standards applicable to such units 

 

307 We would also note that the EPA, as a part of the Industrial 

Boiler MACT reconsideration proposal that was signed on December 

2, 2011, is proposing to establish work practice standards for 

control of dioxins and furans from industrial boilers.
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pursuant to CAA section 112(h).

We are finalizing that new or existing EGUs are “coalfired” if they combust coal more than 10 percent of the average 

annual heat input during any 3 consecutive calendar years or for 

more than 15 percent of the annual heat input during any one 

calendar year and meet the final definition of “fossil fuelfired.” We are finalizing that an EGU is considered to be in the 

coal-fired “unit designed for coal greater than or equal to 

8,300 Btu/lb” subcategory if the EGU: 1) meets the final 

definitions of “fossil fuel-fired” and “coal-fired electric 

utility steam generating unit;” and 2) is not a coal-fired EGU 

in the “unit designed for low rank virgin coal” subcategory. 

We are finalizing that the EGU is considered to be in the 

“unit designed for low rank virgin coal” subcategory if the EGU: 

1) meets the final definitions of “fossil fuel-fired” and “coalfired electric utility steam generating unit;” and 2) is 

designed to burn and is burning nonagglomerating virgin coal 

having a calorific value (moist, mineral matter-free basis) of 

less than 19,305 kJ/kg (8,300 Btu/lb) and that is constructed 

and operates at or near the mine that produces such coal.308

We are finalizing that the EGU is considered to be an IGCC 

unit if the EGU: 1) combusts a synthetic gas derived from

 

308 ASTM Method D388-05, “Standard Classification of Coals by 

Rank” (incorporated by reference, see §63.14)
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gasified coal or solid oil-derived fuel (e.g., petroleum coke, 

pet coke), 2) meets the final definition of “fossil fuel-fired,”

and 3) is classified as an IGCC unit. We are not subcategorizing 

IGCC EGUs based on the source of the syngas used (e.g., coal, 

petroleum coke). Based on information available to the Agency, 

although the fuel characteristics of coal and petcoke are quite 

different, the syngas products from both feedstocks have similar 

HAP content and similar HAP emissions characteristics that can 

be controlled in a similar manner.

309

We are finalizing that the EGU is considered to be in the 

“Continental liquid oil-fired” subcategory if 1) meets the final 

definitions of “oil-fired electric utility steam generating 

unit” and “fossil fuel-fired;” and 2) is located in the 

continental United States (U.S.). 

We are finalizing that the EGU is considered to be “Noncontinental liquid oil-fired” subcategory if 1) meets the final 

definitions of “oil-fired electric utility steam generating 

unit” and “fossil fuel-fired;” and 2) is located outside 

continental U.S. 

We are finalizing that the EGU is considered to be “solid 

oil-derived fuel-fired” if 1) the EGU is not a coal-fired EGU 

 

309 U.S. Department of Energy, Wabash River Coal Gasification 

Repowering Project. Project Performance Summary; Clean Coal 

Technology Demonstration Program. DOE/FE-0448. July 2002. EPAHQ-OAR-2009-0234-2933.
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and burns solid oil-derived fuel (e.g., petroleum coke, pet 

coke); and 2) meets the final definitions of “oil-fired electric 

utility steam generating unit” and “fossil fuel-fired.”

We are finalizing that the EGU is considered to be a 

“limited-use liquid oil-fired” if 1) the EGU meets the final 

definitions of “oil-fired electric utility steam generating 

unit” and “fossil fuel-fired;” and 2) has an annual capacity 

factor of less than 8 percent of its maximum or nameplate heat 

input, whichever is greater, averaged over a 24-month block 

contiguous period commencing.

E. What are the requirements during periods of startup, 

shutdown, and malfunction?

As discussed below in section VI.E., for startup and 

shutdown, the requirements have changed since proposal. For 

periods of startup and shutdown, the EPA is finalizing work 

practice standards in lieu of numeric emission limits. Numeric 

emission limits apply for all other periods for all pollutants, 

except organic HAP. For malfunctions, the EPA is finalizing an 

affirmative defense for exceedances of the numerical emission 

limits that are caused by malfunctions.

F. What are the testing and initial compliance requirements?

We are requiring that you, as an owner or operator of a new 

or existing coal- or oil-fired EGU, must conduct performance 
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tests to demonstrate compliance with all applicable emission 

limits. For units using certified continuous emissions 

monitoring systems (CEMS) that directly measure the regulated 

pollutant under final 40 CFR Part 63, subpart UUUUU (e.g., Hg 

CEMS, HCl CEMS, HF CEMS, SO2 CEMS (where an SO2 limit applies as 

the alternative equivalent standard)), or sorbent trap 

monitoring systems, the initial performance test consists of all 

valid data recorded with the certified monitoring system in the 

first 30 boiler operating days of data collected with the 

certified monitoring system prior to the initial compliance 

demonstration date specified in §63.10005. A source may also 

elect to use a PM CEMS to demonstrate compliance with the 

filterable PM emission limit. If this option is selected, then 

the same provisions as noted above for other CEMS will apply. 

(Note that EPA anticipates that the PM monitoring device that 

may most often will be used is a PM continuous parameter 

monitoring system (CPMS) in conjunction with an operating limit, 

as more fully described below.) For units and pollutants not 

being monitored via CEMS, the owner or operator of an affected 

unit must perform the initial performance testing in accordance 

with established EPA reference test methods or the voluntary 

consensus standard methods incorporated by reference. You, as 

the owner or operator of an affected unit, must conduct the 
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following compliance tests where applicable:

(1) For coal-fired units, IGCC units, and solid oil-derived 

fuel-fired units, if you elect to comply with the filterable PM 

emission limit, you must conduct filterable PM emissions testing 

using EPA Method 5 from Appendix A to part 60 of chapter 40 to 

determine initial compliance. Alternatively, if you elect to 

comply with the total non-mercury HAP metals emission limit or 

the individual non-mercury HAP metals emissions limits, you must 

conduct HAP metals testing using EPA Method 29 from Appendix A 

to part 60 of chapter 40. Note for this rule that the filter 

temperature for each Method 5 or 29 emissions test must be 

maintained at 160o ± 14oC (320o ± 25oF), and the material in 

Method 29 impingers must be analyzed for metals content. 

Whenever metals testing is performed with Method 29, you must 

report the front half and back half analytical fractions 

separately. 

(2) For coal-fired, IGCC, and solid oil-derived fuel-fired 

units, you must use a Hg CEMS or a sorbent trap monitoring 

system for both initial compliance and continuous compliance 

using the continuous Hg monitoring provisions of Appendix A to 

40 CFR Part 63, subpart UUUUU, except where the low emitting EGU 

(LEE) requirements apply (see below). The initial performance 

test consists of all valid data recorded with the certified Hg 
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monitoring system in the 30 boiler operating days of data 

collected with the certified monitoring system by the initial 

compliance demonstration date specified in §63.10005. 

(3) For coal-fired and solid oil-derived fuel-fired units 

and new or reconstructed IGCC units that employ FGD technology 

and elect to meet the alternative SO2 limit in place of the HCl 

limit, you need not conduct an initial stack test for HCl or SO2. 

Instead, the 30 boiler operating days of data collected with the 

certified SO2 CEMS by the initial compliance demonstration date 

specified in §63.10005 are used to determine initial compliance, 

and the SO2 CEMS is used thereafter to demonstrate continuous 

compliance. If you instead opt to meet the HCl limit and use an 

HCl CEMS for compliance, you need not conduct an initial stack 

test for HCl. Instead, the 30 boiler operating days of data 

collected with the certified HCl CEMS by the initial compliance 

demonstration date specified in §63.10005 are used to determine 

initial compliance. For units not using the SO2 or HCl CEMS 

options, you must conduct an initial stack test for HCl using 

EPA Method 26, 26A, or 320 from Appendix A to part 60 of chapter 

40. You may use EPA Method 26 or 320 or ASTM Method D6348-03

(Reapproved 2010) with additional quality assurance if no 

entrained water droplets exist in the exhaust gas, but you must 

use Method 26A if entrained water droplets exist in the exhaust 
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gas.

(4) For liquid oil-fired units, you must conduct initial 

performance testing as follows. If you elect to meet the 

filterable PM limit instead of the non-mercury metals limit 

(total or individual), then use Method 5 with the filter 

material maintained at 160o ± 14oC (320o ± 25oF). Alternatively, 

you may use a PM CEMS as discussed elsewhere in this preamble.

If you elect to meet either the total or individual HAP metals 

limit, you will use Method 29 for all non-mercury HAP metals.

For Hg, conduct emissions testing using EPA Method 29 or 30B

from Appendix A to part 60 of chapter 40, or ASTM Method D6784-

02 (Reapproved 2008). For acid gases, conduct HCl and HF testing 

using EPA Method 26A, 320, or 26; or you may elect to comply by 

using an HCl CEMS and/or an HF CEMS; or under certain conditions 

you may choose to demonstrate compliance by measuring fuel 

moisture to demonstrate that moisture content is no greater than 

1.0 percent. You must measure daily if fuel is delivered 

continuously or per shipment if fuel is delivered on a batch 

basis, or you may use a fuel moisture content certification 

provided by your fuel supplier. If you use a CEMS, then use the 

30 boiler operating days of data collected with the certified 

monitoring system by the initial compliance demonstration date 

specified in §63.10005 to determine initial compliance.
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(5) For the required performance stack tests, if you are 

demonstrating compliance with a heat-input based standard, you 

must conduct concurrent O2 or carbon dioxide (CO2) emission 

testing using EPA Method 3A or 3B from appendix A to part 60 of 

chapter 40 or ANSI/ASME PTC 19.10-1981 and then use an 

appropriate equation, selected from among Equations 19–1 through 

19–9 in EPA Method 19 from appendix A to part 60 of chapter 40, 

to convert measured pollutant concentrations to lb/MMBtu values. 

Multiply the lb/MMBtu value by one million to get the lb/TBtu 

value (where applicable). If you choose to meet an electrical 

output-based emissions limit, you must also collect concurrent 

stack gas flow rate and electrical production data. 

(6) For an existing unit that you believe will qualify as 

LEE for Hg, you must conduct an initial Method 30B test over 30 

days and follow the calculation procedures in the final rule to 

document a potential to emit less than 10 percent of the

applicable Hg emissions limit or less than 29 pounds of Hg per 

year. If your unit qualifies as a LEE for Hg, you must conduct 

subsequent performance tests on an annual basis to demonstrate 

that the unit continues to qualify. For all other pollutants, 

you must conduct the initial compliance test, and then all other 

required tests over a 3-year period, and in all such tests, your 

emission results must be less than 50 percent of the applicable 
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emission limit. If you qualify as a LEE on that basis, you must 

conduct subsequent performance tests every 3 years to 

demonstrate that the unit continues to qualify.

(7) You may use results from tests conducted no earlier 

than 12 months before the compliance date of this rule as the 

initial performance test for an applicable pollutant, provided 

that:

a. You certify and keep records demonstrating that no 

significant changes have occurred,

b. Tests were conducted using methods allowed in this rule

in accordance with §63.10007 and Table 5,

c. You have records of all parameters needed to convert 

results to units of the standard for the entire period, and

d. For a CEMS-based performance test, you have all the 

required data for the entire 30-boiler operating day rolling 

average period.

Operating limit for PM CEMS

Under the final rule, you may elect to comply continuously 

with an operating limit, established during the initial 

performance test, to demonstrate continuous compliance with the

filterable PM, total non-mercury HAP metals, or individual nonmercury HAP metals limit. You will use a PM CPMS to monitor

compliance with the operating limit. The PM CPMS operating 
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principle must be based on in-stack or extractive light scatter, 

light scintillation, beta attenuation, or mass accumulation 

detection of the exhaust gas or representative exhaust gas 

sample. The reportable measurement output from the PM CPMS may 

be expressed as milliamps, stack concentration, or other raw 

data signal. Meeting the operating limit serves as your

demonstration of continuous compliance with the filterable PM, 

total non-mercury HAP metals, or individual non-mercury HAP 

metals limit. As mentioned earlier, if you use this method to 

demonstrate continuous compliance, you must install a PM CPMS 

and establish the operating limit during the initial compliance 

test for filterable PM, total non-mercury HAP metals, or 

individual non-mercury HAP metals. As noted below, when you use 

this operating limit, you can reduce stack testing frequency to 

demonstrate ongoing compliance. You may also opt to install and 

operate a PM CEMS certified in accordance with Performance 

Specification 11 and Procedure 2 of 40 CFR part 60, Appendices B 

and F, respectively. If you elect to use this option, then the 

requirements for quarterly testing with Method 5, or annual 

testing and use of a PM CPMS, are no longer applicable.

Dioxins/furans and non-dioxin/furan organic HAP

For dioxins and furans and non-dioxin/furan organic HAP, 

you must submit documentation that you have conducted a 
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combustion process tune-up, a thorough equipment inspection, and 

an optimization to minimize generation of CO and NOX, all meeting 

the requirements of this final rule. The work practice standard 

involves maintaining and inspecting the burners and associated 

combustion controls, tuning the specific burner type to optimize 

combustion, obtaining and recording CO and NOX values before and 

after burner adjustments, keeping records of activity and 

measurements, and submitting a report for each tune-up 

conducted. You must collect CO and NOX data and may use portable 

analyzers (which include handheld or similar devices) to monitor 

and verify the results. The specific details are addressed in 40

CFR section 63.10021 of the final rule.

This same work practice standard also applies in place of 

any emission limits for Hg, non-mercury metals HAP, acid gas 

HAP, dioxins and furans, and non-dioxin/furan organic HAP from a 

limited-use, liquid oil-fired EGU (i.e., a unit that has an 

annual capacity factor on oil of less than 8 percent of its 

maximum or nameplate heat input, whichever is greater). The EPA

established this subcategory in response to comments and a 

further analysis of the units within this subcategory in the ICR 

database. For these units, EPA believes that the required work 

practice standards are appropriate and consistent with the 

requirement of CAA section 112(h).
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G. What are the continuous compliance requirements?

To demonstrate continuous compliance with the emission 

limitations, the final rule includes the following requirements:

(1) Use of CEMS. Where a CEMS or a sorbent trap monitoring 

system is used for demonstrating initial compliance, you also 

must use the CEMS or sorbent trap monitoring system on a 

continuous basis to demonstrate ongoing compliance with the 

numerical emission limits. CEMS or sorbent trap monitoring 

system data are not used to determine compliance with the work 

practice standards applicable during periods of startup and 

shutdown, but sources that install a CEMS or a sorbent trap 

monitoring system to demonstrate compliance with the numerical 

emission limits must operate the system at all times, as EPA 

intends to evaluate the continuous monitoring data from start-up 

and shutdown periods as discussed below. You must calculate a 

rolling average for each successive 30-boiler operating day 

rolling average period. All valid data collected during each 

successive period will be used to demonstrate compliance, except 

for data collected during periods of startup and shutdown; 

during those periods, the owner or operator must meet work 

practice requirements instead of the numerical emission limits. 

There is no numerical minimum data availability required to 

constitute a valid 30-boiler operating day rolling average; 
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however, you must monitor at all times that the process is in 

operation (including during startups and shutdowns, although 

emissions during these periods are not included in the 30-boiler 

operating day average). You must operate, maintain, and qualityassure the CEMS or sorbent trap monitoring systems in accordance 

with the provisions in 40 CFR section 63.10010 and Appendix A 

and B of the final rule (for Hg, HCl, and HF CEMS), in 

accordance with Performance Specification 11 in Appendix B to 40 

CFR Part 60 and Procedure 2 in Appendix F to Part 60 (for PM 

CEMS used for direct compliance), or in accordance with 40 CFR 

Part 75 (for SO2 CEMS, and certain ancillary monitors such as a 

diluent or moisture monitor).

For each unit using HCl, HF, SO2, PM, or Hg CEMS or a 

sorbent trap monitoring system for continuous compliance, you 

must install, certify, maintain, operate and quality-assure the 

additional CEMS (e.g., CEMS that measure O2 or CO2 concentration, 

stack gas flow rate, and, if default moisture values are not 

used, moisture content) needed to convert pollutant 

concentrations to units of the emission standards or operating 

limits. Where appropriate, you must certify and quality-assure 

these additional CEMS according to 40 CFR Part 75.

For HCl and HF CEMS, the EPA is adding monitoring 

provisions as Appendix B to 40 CFR Part 63, subpart UUUUU. 
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Appendix A references performance specification (PS) 15 of 

Appendix B to 40 CFR Part 60 for Fourier Transform Infrared 

(FTIR) CEMS for procedures to certify and conduct ongoing 

quality assurance on these FTIR CEMS. In addition, we expect to 

publish a PS specific to HCl CEMS in the near future (prior to 

the compliance date of this rule). In the meantime, you may 

petition the Administrator under the procedure given in 40 CFR 

section 63.7(f) for an alternative approach to compliance 

monitoring or testing for HCl or any other regulated pollutant.

When using a sorbent trap monitoring system, you may use 

each pair of sorbent traps to collect Hg samples for no more 

than 15 boiler operating days. Under the general duty to monitor 

at all times, you must replace traps in a timely manner to 

ensure that Hg emissions are sampled continuously.

For Hg monitoring, the EPA is adding Hg monitoring 

provisions as Appendix A to 40 CFR Part 63, subpart UUUUU, and 

requiring use of these provisions to document continuous 

compliance with the rule for coal-fired, IGCC, and solid oil 

derived-fired units that cannot qualify as LEEs. Appendix A 

consolidates all Hg monitoring provisions.

Today’s rule provides two basic Hg continuous monitoring 

options: Hg CEMS and sorbent trap monitoring systems. Appendix A 

requires initial certification and periodic quality assurance 
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(QA) testing of the Hg CEMS and sorbent trap monitoring systems. 

The certification tests required for the Hg CEMS are a 7-day 

calibration error test; a linearity check, using NIST-traceable 

elemental Hg standards; a 3-level system integrity check 

(similar to a linearity check), using NIST-traceable oxidized Hg 

standards; a cycle time test; and a relative accuracy test audit 

(RATA). Table A–1 of Appendix A summarizes the performance 

specifications for the required certification tests. For ongoing 

QA of the Hg CEMS, Appendix A requires daily calibrations, 

weekly single-point system integrity checks, quarterly linearity 

checks (or 3-level system integrity checks), and annual RATAs. 

Table A-2 in Appendix A summarizes these ongoing QA test 

requirements and the applicable performance criteria for Hg 

CEMS, which are consistent with those published in support of 

CAMR and are, thus, familiar to the industry.

For sorbent trap monitoring systems, a RATA is required for 

initial certification, and annual RATAs are required for ongoing 

QA. The performance specification for these RATAs is the same as 

for the RATAs of the Hg CEMS. Bias adjustment of the measured Hg 

concentration data is not required. For day-to-day operation of 

the sorbent trap system, Appendix A requires you to follow the 

procedures and QA/QC criteria in PS 12B in Appendix B to 40 CFR 

Part 60. PS 12B is nearly identical to the Appendix K to 40 CFR 
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Part 75, published in support of CAMR and with which the 

industry is familiar. The 40 CFR Part 75 concepts of:

a. determining the due dates for certain QA tests on the 

basis of “QA operating quarters” and 

b. grace periods for certain QA tests 

apply to both Hg CEMS and sorbent trap monitoring systems. 

Mercury concentrations measured by Hg CEMS or sorbent trap 

systems are used together with hourly flow rate, diluent gas, 

moisture, and electrical load data, to express the Hg emissions 

in units of the rule, on an hourly basis (i.e., lb/TBtu or 

lb/GWh). Section 6 of Appendix A provides the necessary 

equations for these unit conversions.

For HCl and HF CEMS, the EPA is adding monitoring 

provisions as Appendix B to 40 CFR Part 63, Subpart UUUUU. 

Appendix A references performance specification (PS) 15 of 

Appendix B to 40 CFR Part 60 for Fourier Transform Infrared 

(FTIR) CEMS for procedures to certify and conduct ongoing 

quality assurance on these FTIR CEMS. In addition, we expect to 

promulgate a generic PS specific to HCl CEMS prior to the 

compliance date of this rule. In the meantime, you may petition 

the Administrator under the procedure given in 40 CFR section 

63.7(f) for an alternative approach to compliance monitoring or 

testing for HCl or any other regulated pollutant.
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(2) Use of stack tests. If you demonstrate initial 

compliance on the basis of a stack test, you must demonstrate 

continuous compliance by conducting periodic stack tests on a 

quarterly basis. This includes filterable PM (or non-mercury HAP 

metals) and HCl from coal-fired and solid oil-derived fuel-fired 

EGUs, and filterable PM (or HAP metals) and HCl and HF from 

liquid oil-fired EGUs with the following exceptions:

a. If you use a PM CPMS and associated operating limit, you 

may conduct the applicable Method 5 or Method 29 test once 

annually rather than quarterly, in which case you must reestablish the operating limit during each performance test. A PM 

CPMS does not need to meet the requirements for a PM CEMS under 

PS 11. The final rule includes basic quality checks that the PM 

CPMS must meet and a requirement for you to develop and follow a 

site-specific monitoring plan to be approved by the delegated 

authority. You must demonstrate compliance with the operating 

limit by using all valid hourly data collected during each 

successive 30-boiler operating day period rolled daily. The 30-

boiler operating day rolling average is calculated by all of the 

valid hourly average PM CPMS output values collected for the 30 

boiler operating days (excluding hours of startup and shutdown; 

see section V.E. of this preamble). 

b. If you combust liquid fuels and if your fuel moisture 
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content is no greater than 1.0 percent, you may demonstrate 

ongoing compliance with HCl and HF emissions limits by 

i. Measuring fuel moisture content of each shipment of fuel 

if your fuel arrives on a batch basis;

ii. Measuring fuel moisture content daily if your fuel 

arrives on a continuous basis; or

iii. Obtaining and maintaining a fuel moisture 

certification from your fuel supplier. 

Should the moisture in your liquid fuel be more than 1.0 

percent, you must 

i. conduct HCl and HF emissions testing quarterly and 

establish site-specific monitoring to demonstrate continued acid 

gas control performance between periodic tests, or

ii. use an HCl CEMS and/or HF CEMS.

c. If your existing unit qualifies as an LEE for Hg, you 

must conduct another 30-day Method 30B performance test on your 

unit once per year to reestablish that the unit continues to 

qualify as a LEE for Hg. If the results of the LEE test show 

that the unit exceeds 10 percent of the emissions limit or 

exceeds the potential to emit 29 pounds of Hg per year, you will 

lose LEE status for the unit. You can regain LEE status for that 

unit if every required performance test for a 3-year period 

shows that emissions from the unit did not exceed the LEE limit. 
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If LEE status is lost for a solid fuel unit, you must commence 

quarterly performance testing until you install, certify, and 

operate a Hg CEMS or a sorbent trap monitoring system, and you 

must complete the installation and certification within 6 months 

of losing LEE status; for a liquid fuel unit, you must commence 

quarterly performance testing.

d. If a liquid oil-fired EGU has an annual capacity factor 

on oil of less than 8 percent of its maximum or nameplate heat 

input, whichever is greater, you must demonstrate continuous 

compliance with the applicable work practice standard by 

conducting at least once every 36 calendar months (48 calendar 

months if a neural network is employed) a combustion process 

tune-up, a thorough equipment inspection, and an optimization to 

minimize generation of CO and NOX, all meeting the requirements 

of this final rule. You must maintain and inspect the burners 

and associated combustion controls, tuning the specific burner 

type to optimize combustion, obtaining and recording CO and NOX

values before and after burner adjustments, keeping records of 

activity and measurements, and submitting a report for each 

tune-up conducted. You must collect CO and NOX data using

portable analyzers (which typically include handheld or similar 

devices). Specific details are addressed in 40 CFR section 

63.10021 of the final rule. In addition, you must record boiler 
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operating hours, by fuel type, in each calendar quarter. 

e. The rule allows a grant of LEE status to existing units 

with test results that show a history of low, non-mercury 

emissions. As mentioned earlier, LEE status reduces testing 

frequency for units. After a 3-year period during which every 

emissions test for a specific pollutant shows emissions no 

greater than 50 percent of the emissions limit, you may reduce 

the emissions testing frequency for that specific non-mercury 

pollutant to once every 36 months. If any subsequent emissions 

test for that pollutant exhibits emissions greater than 50 

percent of the emissions limit, you must revert to the original 

emissions testing frequency until you re-establish a 3-year 

period of very low emissions no greater than 50 percent of the 

standard.

f. For liquid oil-fired units that demonstrate continuous 

compliance with quarterly performance tests for HCl and HF 

emission limits rather than through use of HCl and HF CEMS, the 

final rule requires a site-specific monitoring plan in addition 

to the quarterly tests. For these pollutants, there is unlikely 

to be any existing underlying monitoring (such as compliance 

assurance monitoring) that serves as an additional tool to 

ensure the source’s operations remain consistent with operating 

conditions during a recent successful performance test. The 
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requirement for a site-specific monitoring plan fills this gap 

and ensures that in between tests, the source continues to 

operate in a manner designed to maintain HCl and HF emissions in 

compliance with the emission limits under this rule. The 

appropriate parameters to monitor will depend on the compliance 

strategy employed by a specific source, and thus EPA is enabling 

the monitoring approach to be established on a case-by-case 

basis. Given the relatively small number of these units and the 

other compliance options available, we anticipate that this 

approach will apply to a small set of units. The monitoring plan 

will identify the parameters monitored, the monitoring methods, 

the QA/QC elements that apply, and the data reduction elements 

(including appropriate averaging periods, as applicable). See 40 

CFR 63.10000(c)(2)(ii).

(3) Work practice standard. For the performance tune-up 

work practice requirements, you must demonstrate continuous 

compliance by conducting the work practice at least once every 

36 calendar months (48 calendar months if a neural network is 

employed). The work practice involves maintaining and inspecting 

the burners and associated combustion controls, tuning the 

specific burner type, as applicable, to optimize combustion, 

obtaining and recording CO and NOX values before and after burner 

adjustments, keeping records of activity and measurements, and 
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submitting a report for each tune-up conducted. A combustion 

tune-up will involve optimizing combustion of the unit 

consistent with manufacturer’s instruction as applicable, or in 

accordance with best combustion engineering practice for that 

burner type.

H. What are the notification, recordkeeping and reporting 

requirements?

All new and existing sources in all subcategories must 

comply with certain requirements of the General Provisions (40 

CFR Part 63, subpart A), which are identified in Table 9 of this 

final rule. The General Provisions include specific requirements 

for notifications, recordkeeping, and reporting. You must submit 

a notification of compliance status report for each unit, 

according to the schedule required by 40 CFR section 63.9(h) of 

the General Provisions, including a certification of compliance. 

Except for units that use CEMS for continuous compliance, 

under this rule you must provide semiannual compliance reports, 

as required by 40 CFR section 63.10(e)(3) of subpart A, that 

indicate whether a deviation from any of the requirements in the 

rule occurred and whether or not any process changes occurred 

and compliance certifications were reevaluated. As discussed 

below, we are finalizing a requirement to use the 40 CFR Part 

75-based Emissions Collection and Monitoring Plan System (ECMPS) 
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for reporting emissions and related data for units using CEMS

for most pollutants. Also, as discussed below, for the PM CPMS, 

PM CEMS, and performance test results, we require you to use 

EPA’s WebFIRE310 database for reporting. 

This rule requires you to keep certain records to 

demonstrate compliance with each emission limit and work 

practice standard. The General Provisions to 40 CFR Part 63 

specify these recordkeeping requirements (see Table 9 to this 

subpart). Among other specific records, you must keep the 

following:

(1) All reports and notifications submitted to comply with 

this rule.

(2) Continuous monitoring data as required in this rule.

(3) Each instance in which you did not meet an emission 

limit, work practice requirement, operating limit, or other 

compliance obligation (i.e., deviations from this rule).

(4) Daily hours of operation by each unit.

(5) As part of the general duty to keep all monitoring 

data, fuel moisture content of liquid fuel, if you elect to 

demonstrate compliance using that information.

 

310 WebFIRE is the Internet version of FIRE. The Factor 

Information Retrieval (FIRE) Data System is a database 

management system containing EPA’s recommended emission 

estimation factors for criteria and HAP. It includes information 

about industries and their emitting processes, the chemicals 

emitted, and the emission factors themselves.
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(6) A copy of the results of all performance tests, monitor 

certifications, performance evaluations, or other compliance 

demonstrations conducted to demonstrate initial or continuous 

compliance with this rule.

(7) A copy of your site-specific performance evaluation 

test plans developed for this rule as specified in 40 CFR 

63.8(e), if applicable.

(8) A copy of your acid gas control system parameter 

monitoring plan under 40 CFR 63.10000(c)(2)(ii).

You also must submit the following additional 

notifications:

(1) Notifications required by the General Provisions.

(2) Initial Notification no later than 120 calendar days 

after you become subject to this subpart.

(3) Notification of Intent to conduct performance tests 

and/or compliance demonstration at least 60 calendar days before 

the performance test and/or compliance demonstration is 

scheduled.

(4) Notification of Compliance Status 60 calendar days 

following completion of the performance test and/or compliance 

demonstration.

Electronic reporting is becoming a common element of modern 

life (as evidenced by electronic banking and income tax filing), 
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and the EPA is beginning to require electronic submittal of 

environmental data. Electronic reporting is already common in 

environmental data collection and many media offices at EPA are 

reducing reporting burden for the regulated community by 

embracing electronic reporting systems as an alternative to 

paper-based reporting.

One of the major benefits of reporting electronically is 

standardization, to the extent possible, of the data reporting 

formats that provides more certainty to users of what data are 

required in specific reports. For example, electronic reporting 

software allows for more efficient data submittal and the 

software’s validation mechanism helps industry users submit 

fewer incomplete reports. This alone saves industry report 

processing resources and reduces transaction times. 

Standardization also allows for development of efficient methods 

to compile and store much of the documentation required to be 

reported by this rule.

Use of electronic reporting system.

We are requiring that you submit certain reports 

electronically. In addition to supporting regulation 

development, control strategy development, and other air 

pollution control activities, having an electronic database 

populated with these reports will save industry, state, local, 
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tribal agencies, the public, and the EPA significant time, 

money, and effort while also improving the transparency and 

quality of emission inventories and, as a result, air quality 

regulations.

The reports to be submitted electronically include all 

performance test reports, notification of compliance status 

reports, compliance, and continuous monitoring data summaries 

specified in 40 CFR section 63.10031 of this rule. Performance 

tests are required to be conducted as described in 40 CFR 63.7 

of the General Provisions. The data that must be submitted as 

the performance test report are also described in 40 CFR 63.7. 

These data must be submitted (except in limited cases) to EPA’s 

WebFIRE database by using the electronic reporting tool (ERT) 

and the Compliance and Emissions Data Reporting Interface

(CEDRI) that is accessed through EPA’s Central Data Exchange 

(CDX), as described below. The data requirements for the 

notification of compliance status and compliance reports are 

described in detail in the regulatory text (40 CFR 63.10031) of 

this rule, but they essentially mirror the requirements in 40 

CFR 63.6 of the General Provisions. These reports will also be 

submitted to WebFIRE using an electronic form found in CEDRI and 

through the CDX as described below. As required in 40 CFR 

63.10031(f)(2) of the final rule, the continuous monitoring 
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summaries are required to be submitted quarterly. The quarterly 

reports must include all of the calculated 30-boiler operating 

day rolling average values derived from the PM CPMS. These 

reports will also be submitted to WebFIRE using an electronic 

form found in CEDRI and through the CDX, as described below. 

This same approach will apply if a source elects to use a PM 

CEMS or receives approval to use a HAP metals CEMS as an 

alternative monitoring method.

The availability of electronic reporting for sources 

subject to the Subpart UUUUU will provide efficiency, improved 

services, better accessibility of information, and more 

transparency and accountability. Additionally, submittal of 

these required reports electronically provides significant 

benefits for regulatory agencies, industry, and the public. The

compliance data electronic reporting system (CEDRI and CDX) is 

being developed such that once a facility’s initial data entry 

into the system is established and a report is generated, 

subsequent data submittal will only consist of electronic 

updates to existing information in the system. Such a system 

will effectively reduce the burden associated with submittal of 

data and reports by reducing the time, costs, and effort 

required to submit and update hard copies of documentation. 

State, local, and tribal air pollution control agencies will
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also benefit from having access to the more streamlined and 

accurate electronic data submitted to the EPA. Electronic 

reporting will allow for an electronic review process rather 

than a manual data assessment, making review and evaluation of 

the source-provided data and calculations easier and more 

efficient. Electronic reporting will also benefit the public by 

generating a more transparent review process and increasing the 

ease and efficiency of data accessibility. Furthermore, 

electronic reporting will reduce the burden on the regulated 

community by reducing the effort involved in data collection and 

reporting activities. In the future, we anticipate there will be 

fewer and less substantial data collection requests in 

conjunction with prospective required residual risk assessments 

or technology reviews. Electronic reporting will substantially 

reduce this burden, because the EPA will already have these data 

available and consolidated in an electronic database named 

WebFIRE. We anticipate that using electronic reporting for the 

required reports will result in an overall reduction in 

reporting costs; for a discussion of the economic and cost 

impacts of electronic reporting, see section XII.D. of this 

preamble.

Another benefit of electronic data submittal is that these 

data will greatly improve the overall quality of existing and 
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new emissions factors by supplementing the pool of emissions 

test data for establishing emissions factors and by ensuring 

that the factors are more representative of current industry 

operational procedures. A common complaint heard from industry 

and regulators is that emission factors are outdated or not 

representative of a particular source category. With timely 

receipt and incorporation of data from most performance tests, 

the EPA will be able to ensure that emission factors, when 

updated, represent the most current range of operational 

practices. 

Data entry of these electronic reports will be through the 

CEDRI that is accessed through EPA’s CDX (www.epa.gov/cdx). Data 

submitted electronically through CEDRI will be stored in CDX as 

an official copy of record. 

Once you have accessed CEDRI, you will select the 

applicable subpart for the report that you are submitting. You 

will then select the report being submitted, enter the data into 

the form, and click on the submit button. In some cases, such as 

with submittal of a notification of compliance status report, 

you will select the report icon, enter basic facility 

information, and then upload the report in a specified file 

format. 

In addition, we believe that there will be value in 
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allowing other reporting forms to be developed and used in cases 

where the other reporting forms can provide an alternate 

electronic file consistent with EPA’s form output format. This 

approach has been used successfully to provide alternatives for 

other electronic forms (e.g., income tax submittal).

In cases where performance test data are to be submitted to 

the EPA, you must enter the performance test data and 

information into the electronic reporting tool (ERT) which can 

be accessed at http://www.epa.gov/ttn/chief/ert/index.html. In 

CEDRI, the user must then upload the ERT file. CEDRI submits a 

copy of the ERT project data file directly to WebFIRE where the 

data are made available. Where performance test reports are 

submitted, WebFIRE notifies the appropriate state, local, or 

tribal agency contact that an ERT project data file was received 

from the source. 

Submitting performance test data electronically to the EPA 

will apply only to those performance tests conducted using test 

methods that will be supported by the ERT. The ERT contains a 

specific electronic data entry form for most of the commonly 

used EPA reference methods. A listing of the pollutants and test 

methods supported by the ERT is available at the ERT website 

listed above.

I. Submission of Emissions Test Results to the EPA
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The EPA has determined that harmonization of the monitoring 

and reporting requirements of this final rule with 40 CFR Part 

75 is appropriate, where the affected industry already has a 

well-defined system for continuous monitoring and reporting of 

emissions under that part. Therefore, the Agency is finalizing 

monitoring and reporting requirements for most CEMS that are 

consistent with 40 CFR Part 75. You must report CEMS data (other 

than PM CEMS data or data from alternative monitoring subject to 

site-specific approval such as a HAP metals CEMS) to the EPA

electronically, on a quarterly basis, using the ECMPS.

The ECMPS process divides electronic data into three 

categories, the first of which is monitoring plan data. You must 

maintain the electronic monitoring plan separately and can 

update it at any time if necessary. The monitoring plan 

documents the characteristics of the affected units (e.g., unit 

type, rated heat input capacity, etc.) and the monitoring 

methodology used for each parameter (e.g., CEMS). The monitoring 

plan also describes the type of monitoring equipment used 

(hardware and software components), includes analyzer span and 

range settings, and provides other useful information. Nearly 

all coal-fired EGUs are subject to the ARP and thus have 

established electronic monitoring plans that describe their 

required SO2, flow rate, CO2 or O2, and, in some cases, moisture 
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monitoring systems. The EPA will adjust the ECMPS monitoring 

plan format to accommodate this same type of information for Hg, 

HCl, and HF CEMS, with the addition of a few codes for the new 

parameters.

The second type of data collected through ECMPS is 

certification and QA test data. These data include data from 

linearity checks, RATAs, cycle time tests, 7-day calibration 

error tests, and a number of other QA tests that are required to 

validate the emissions data. You may submit the results of these 

tests to the EPA as soon as you obtain the results, with one 

notable exception. Daily calibration error tests are not treated 

as individual QA tests, due to the large number of records 

generated each quarter. Rather, these tests must be included in 

the quarterly electronic reports, along with the hourly 

emissions data. The ECMPS system is set up to receive and 

process certification and QA data from SO2, CO2, O2, flow rate, 

and moisture monitoring systems that are installed, certified, 

maintained, operated, and quality-assured according to 40 CFR 

Part 75. EGUs routinely submit these data to the EPA under the 

ARP and other emissions trading programs.

To accommodate the certification and QA tests for Hg CEMS, 

other CEMS, and sorbent trap monitoring systems, the structure 

and functionality of ECMPS needs relatively few changes, because 
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most of the tests are the same as those required for other gas 

monitors. For reporting Hg, HCl, SO2, and HF CEMS data under this 

rule, we are disabling ECMPS’ 40 CFR Part 75 bias test (which is 

required for certain types of monitors under the EPA’s SO2 and 

NOX emissions trading programs). The bias adjustment of the data 

from these monitors is unnecessary for compliance with the rule.

The third type of data collected through ECMPS is the 

hourly emissions data, which, as previously noted, is reported 

on a quarterly schedule. You must submit reports within 30 days 

after the end of each calendar quarter. The emissions data 

format requires hourly reporting of all measured and calculated 

emissions values, in a standardized electronic format. You must 

report direct measurements made with CEMS, such as gas 

concentrations, in a Monitor Hourly Value (MHV) record. A 

typical MHV record for gas concentration includes data fields 

for:

(1) the parameter monitored (e.g., SO2); 

(2) the unadjusted and bias-adjusted hourly concentration 

values (note that if bias adjustment is not required, only the 

unadjusted hourly value is reported); 

(3) the source of the data, i.e., a code indicating either 

that each reported hourly concentration is a quality assured 

value from a primary or backup monitor, or that quality-assured 
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data were not obtained for the hour; and 

(4) the percent monitor availability (PMA), which is 

updated hour-by-hour. This generic record structure could easily 

accommodate hourly average measurements from CEMS used under 

this rule.

The ECMPS reporting structure is quite flexible, which 

makes it useful for assessing compliance with various emission 

limits. The Derived Hourly Value (DHV) record allows 

calculations of a wide variety of quantities from the reported 

hourly emissions data. For instance, if an emission limit is 

expressed in units of lb/MMBtu, the DHV record can be used to 

report hourly pollutant concentration values in these units of 

measure, since the lb/MMBtu values can be derived from the 

hourly pollutant and diluent gas (CO2 or O2) concentrations 

reported in the MHV records. The ECMPS can also accommodate 

multiple DHV records for a given hour in which more than one 

derived value is required to be reported. The system will 

support reporting hourly data in the units of the emission 

standards (e.g., lb/MMBtu, lb/TBtu, lb/GWh, etc.) when hourly Hg 

concentration data are reported through ECMPS using the DHV 

record, in conjunction with the appropriate equations and 

auxiliary information such as heat input and electrical load 

(all of which are reported hourly in the emissions reports).
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One change in this rule from standard 40 CFR Part 75

emissions data reporting is elimination of the requirement to 

provide substitute data calculations within ECMPS. The ARP and 

other emissions trading programs that report emissions data to 

the EPA using 40 CFR Part 75 require provision of a complete 

data record. Emissions data are required to be reported for 

every unit operating hour. When CEMS are out of service, 

substitute data must be reported to fill in the gaps. However, 

for the purposes of compliance with a NESHAP, reporting 

substitute data during monitor outages is not necessary, as 

quantification of total mass emissions is not the focus of the 

rule. Hours when a monitoring system is out of service would be 

counted as hours of monitor down-time and may be a deviation 

from the monitoring requirements of this rule unless the rule 

provides an exception, as it does for routine quality control 

and maintenance activities.

In contrast to the CEMS-related data that would be 

submitted through ECMPS, you must submit reports of performance 

tests and PM CPMS data to EPA’s WebFIRE database by using CEDRI 

that is accessed through EPA’s CDX (www.epa.gov/cdx). You must 

submit performance test data in the file format generated 

through use of EPA’s ERT (see

http://www.epa.gov/ttn/chief/ert/index.html) within 60 days of 
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performance test completion. Electronic data submittal

requirements are described in section V.H. of this preamble.

Other notifications and reports not currently accepted by 

the electronic reporting system will be submitted in hardcopy 

form at this time.

VI. Summary of Significant Changes Since Proposal

The previous section described the requirements that EPA is 

finalizing in this rule. This section will discuss in greater 

detail the key changes EPA is making from the proposed. These 

changes result from EPA’s review of the additional data and 

information provided to us and our consideration of the many 

substantive and thoughtful comments submitted on the proposal. 

While our approach and methodology to establishing the standards 

remain the same, the changes make the final rule more flexible 

and cost-effective, reduce reliability concerns and improve 

clarity, while fully preserving, or improving, the public health 

and environmental protection required by the CAA.

A. Applicability

Since proposal, the EPA has made certain changes to the 

applicability provisions of the final rule to provide clarity. 

These changes do not change the universe of sources subject to 

the rule.

The EPA is revising a number of the proposed definitions 
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and adding a definition for “natural gas-fired electric utility 

steam generating unit” in the final rule to provide clarity to 

the regulated community concerning the standards applicable to 

coal- and oil-fired EGUs. 

In the proposed rule, the EPA defined “[e]lectric utility 

steam generating unit” consistent with the CAA section 112(a)(8) 

definition:

a fossil fuel-fired combustion unit of more than 25 

megawatts electric (MWe) that serves a generator that 

produces electricity for sale. A fossil fuel-fired 

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 

considered an electric utility steam generating unit. 

40 CFR 63.10042.

We also indicated how we would determine whether units were 

coal-fired or oil-fired fired EGUs: “If an EGU burns coal 

(either as a primary fuel or as a supplementary fuel), or any 

combination of coal with another fuel (except solid waste as 

noted below), the unit is considered to be coal fired under this 

proposed rule. If a unit is not a coal-fired unit and burns only 

oil, or oil in combination with another fuel other than coal 
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(except as noted below), the unit is considered to be oil fired 

under this proposed rule.” 76 FR 25020. 

We proposed a definition for the term “fossil fuel-fired”

because that term was not defined in the statute and we wanted 

to clarify the level of fossil fuel combustion necessary to 

satisfy the CAA section 112(a)(8) definition of EGU. The 

definition focused on coal and oil combustion because the EPA

was only regulating coal- and oil-fired EGUs in this final rule. 

The proposed definition contained two primary elements: 1) the 

unit must be capable of combusting sufficient amounts of coal or 

oil to generate the equivalent of 25 megawatts electrical 

output; and 2) the unit must have fired coal or oil for more 

than 10.0 percent of the average annual heat input during the 

previous 3 calendar years or for more than 15.0 percent of the 

annual heat input during any one of those calendar years. 76 FR 

25025. We further stated that for a unit to be “capable of 

combusting” coal or oil the unit must have a permit that 

authorized the combustion of coal or oil and also have the 

appropriate fuel handling facilities on-site. Id. 

As explained in the proposed rule, natural gas-fired EGUs 

were not included in the December 2000 listing so such units 

that otherwise met the CAA section 112(a)(8) definition of EGU 

because of natural gas combustion are not subject to the final 
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rule. In the proposed rule, we stated that an EGU that “combusts 

natural gas exclusively or natural gas in combination with 

another fuel where the natural gas constitutes 90 percent or 

more of the average annual heat input during the previous 3 

calendar years or 85.0 percent or more of the annual heat input 

during any one of those calendar years” was not subject to the 

rule. Id. The references to 90 percent natural gas combustion 

over 3 years and 85 percent natural gas combustion in any one 

year were included to align with the definitions of “fossil 

fuel-fired” so that it would be clear that units combusting 

primarily natural gas would not be considered coal-fired, oilfired, or IGCC EGUs if they burned 10 percent or less of coal, 

oil, or synthetic gas derived from coal or solid oil over 3

years or 15 percent or less of such fuels in any one year. We 

did not intend to suggest that to be considered a fossil fuelfired EGU a natural gas-fired unit that is not a coal-fired or 

oil-fired EGU would have to combust natural gas that exceeded 

the 10 percent/15 percent thresholds set forth in the proposed 

rule. In fact, in 40 CFR 63.9983 of the proposed rule, we stated 

that “[a]ny EGU that is not a coal- or oil-fired EGU and 

combusts natural gas more than 10.0 percent of the average 

annual heat input during the previous 3 calendar years or for 

more than 15.0 percent of the annual heat input during any one 
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of those calendar years” is not subject to this subpart.

We further explained that the percentages included in the 

definition of “fossil fuel-fired” would prevent units that 

primarily combusted fuels other than fossil fuels from being 

subjected to the final rule:

Units that do not meet the definition of fossil-fuel 

fired would, in most cases, be considered IB units 

subject to one of the Boiler NESHAP. Thus, for 

example, a biomass-fired EGU, regardless of size, that 

utilizes fossil fuels for startup and flame 

stabilization purposes only (i.e., less than or equal 

to 250 MMBtu/hr and used less than 10.0 percent of the 

average annual heat input during the previous 3 

calendar years or less than 15.0 percent of the annual 

heat input during any one of those calendar years) is 

not considered to be a fossil fuel-fired EGU under 

this proposed rule. The EPA has based its threshold 

value on the definition of “oil-fired” in the ARP 

found at 40 CFR 72.2. As EPA has no data on such use 

for (e.g.) biomass co-fired EGUs because their use has 

not yet become commonplace, we believe this definition 

also accounts for the use of fossil fuels for flame 

stabilization use without inappropriately subjecting 
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such units to this proposed rule. Id.

Thus, in the proposed rule, we intended to create 

thresholds to determine when a unit is fossil fuel-fired and for 

which fossil fuel the unit is fossil fuel-fired. We intended to 

include a unit combusting more than the defined amount of coal 

in one of the coal-fired EGU subcategories. If a unit is not 

coal-fired and it is combusting more than the defined amount of 

oil, we intended to include the unit in one of the oil-fired EGU 

subcategories. We also intended to make clear that EGUs that are 

neither coal-fired nor oil-fired but combust more than the 

defined amount of natural gas are natural gas-fired EGUs not 

subject to the final standards. However, the definitions, as 

proposed, were not sufficiently descriptive.

For example, we included a definition for “coal-fired 

electric utility steam generating unit” that did not include the 

requirement that the unit must combust coal for at least 10 

percent of the heat input over 3 years or 15 percent of the heat 

input in any one year. Instead, in the proposed rule we 

indicated that a unit was coal-fired if it burned coal in any 

amount. We did not intend to define a unit as coal-fired if it 

burned coal that accounted for 10 percent or less over 3 years 

or 15 percent of less in any one year, as that would be 

inconsistent with the definition of fossil fuel-fired and the 
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definitions for the oil-fired EGU subcategories. Under the 

proposed rule construct, a unit that combusts mostly biomass and 

less than 10 percent coal over 3 years would not be a coal-fired 

EGU because it would not meet the “fossil fuel-fired”

definition. But a unit burning mostly petroleum coke and less 

than 10 percent coal over 3 years might be considered a coalfired EGU because it would meet the definition of “fossil fuelfired” and be burning some coal, even though that level of coal 

combustion alone would not be sufficient to make the unit 

“fossil fuel-fired” for coal. That result is at odds with our 

intent. The same would hold true for an EGU that combusts mostly 

natural gas and less than 10 percent synthetic gas derived from 

coal over a 3-year period. Our proposal preamble makes clear 

that we did not intend this result because we specifically 

stated that units burning 90 percent or more natural gas over a 

3-year period would be considered natural-gas fired EGUs. 76 FR 

25025. 

In addition, we proposed to define “[u]nit designed to burn 

solid oil fuel subcategory” to include any EGU that burned a 

solid fuel derived from oil for more than 10.0 percent of the 

average annual heat input during the previous 3 calendar years 

or for more than 15.0 percent of the annual heat input during 

any one of those calendar years, either alone or in combination 
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with other fuels. We also included the 10 percent/15 percent 

thresholds in the definition for the liquid oil subcategory, 

but, as stated above, we did not include the thresholds in the 

definition of “coal-fired” EGU. Therefore, there would be some 

confusion for a source that blended coal with solid oil derived 

fuel (e.g., petroleum coke). For example, the owner or operator 

of an EGU that burned sufficient solid oil-derived fuel that 

accounted for 80 percent of the heat input in a given year and 

the remainder of the fuel was coal would not be sure which 

standard applied because the definitions in the proposed rule 

were internally inconsistent.

For these reasons, we are revising the definitions for 

“coal-fired electric utility steam generating unit,” “integrated 

gasification combined cycle electric utility steam generating 

unit,” and “oil-fired electric utility steam generating unit,”

and we are adding a definition of “natural-gas fired electric 

utility steam generating unit” as follows: 

Coal-fired electric utility steam generating unit

means an electric utility steam generating unit 

meeting the definition of “fossil fuel-fired” that 

burns coal or coal refuse for more than 10.0 percent 

of the average annual heat input during any 3 

consecutive calendar years or for more than 15.0 
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percent of the annual heat input during any one 

calendar year.

Integrated gasification combined cycle electric 

utility steam generating unit or IGCC means an 

electric utility steam generating unit meeting the

definition of “fossil fuel-fired” that burns a 

synthetic gas derived from coal and/or solid oilderived fuel for more than 10.0 percent of the average 

annual heat input during any 3 consecutive calendar 

years or for more than 15.0 percent of the annual heat 

input during any one calendar year in a combined-cycle 

gas turbine. No coal or solid oil-derived fuel is 

directly burned in the unit during operation.

Natural gas-fired electric utility steam generating 

unit means an electric utility steam generating unit 

meeting the definition of “fossil fuel-fired” that is 

not a coal-fired, oil-fired, or IGCC electric utility 

steam generating unit and that burns natural gas for 

more than 10.0 percent of the average annual heat 

input during any 3 consecutive calendar years or for 

more than 15.0 percent of the annual heat input during 

any one calendar year.

Oil-fired electric utility steam generating unit means 
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an electric utility steam generating unit meeting the 

definition of “fossil fuel-fired” that is not a coalfired electric utility steam generating unit and that 

burns oil for more than 10.0 percent of the average 

annual heat input during any 3 consecutive calendar 

years or for more than 15.0 percent of the annual heat 

input during any one calendar year.

In addition to these changes, we are revising the 

definition of “fossil fuel-fired” based on comments. We are 

revising the definition to remove the heat input equivalent of 

25 MW because commenters noted that the equivalency used (taken 

from 40 CFR Part 60, subpart Da) could not be applied 

consistently because of differing boiler efficiencies. 

Commenters noted that owners/operators were familiar with the 

use of the “MW” term for the boilers and boilers include 

nameplate capacities that are readily identifiable.

We are also including a revision to the definition so that 

the fossil fuel combustion thresholds of 10 percent over 3 

consecutive years and 15 percent in one year are evaluated after 

the applicable compliance date of the final rule on a rolling 

basis. Commenters correctly noted that some existing coal- and 

oil-fired EGUs will convert their units to alternative fuels 

(e.g., natural gas or biomass) and if the definition were
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finalized as proposed such units could be improperly subjected 

to the final standards.

The new definition is as follows:

Fossil fuel-fired means an electric utility steam 

generating unit (EGU) that is capable of combusting 

more than 25 MW of fossil fuels. To be “capable of 

combusting” fossil fuels, an EGU would need to have 

these fuels allowed in their operating permits and 

have the appropriate fuel handling facilities on-site

or otherwise available (e.g., coal handling equipment, 

including coal storage area, belts and conveyers, 

pulverizers, etc.; oil storage facilities). In 

addition, fossil fuel-fired means any EGU that fires

fossil fuels for more than 10.0 percent of the average 

annual heat input in any 3 consecutive calendar years 

or for more than 15.0 percent of the annual heat input 

during any one calendar year after the applicable 

compliance date.

For clarity, we are also removing the definition of “[u]nit 

designed to burn liquid oil fuel subcategory,” revising the 

definition of “[u]nit designed to burn solid oil fuel 

subcategory,” adding definitions for the continental and noncontinental liquid oil-fired EGU subcategories, and adding a 
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definition of a limited-use liquid oil-fired EGU as follows:

Continental liquid oil-fired subcategory means any 

oil-fired electric utility steam generating unit that 

burns liquid oil and is located in the continental 

United States.

Limited-use liquid oil-fired subcategory means an oilfired electric utility steam generating unit with an 

annual capacity factor of less than 8 percent of its 

maximum or nameplate heat input, whichever is greater, 

averaged over a 24-month block contiguous period 

commencing [INSERT DATE 60 DAYS AND 3 YEARS AFTER THE 

DATE OF PUBLICATION IN THE FEDERAL REGISTER].

Non-continental liquid oil-fired subcategory means any 

oil-fired electric utility steam generating unit that 

burns liquid oil and is located outside the 

continental United States.

Unit designed to burn solid oil-derived fuel 

subcategory means any oil-fired EGU that burns solid 

oil-derived fuel.

In the proposed rule, we stated that we believed EGUs may 

at times not meet the definition of an EGU subject to this 

subpart. For example, we explained that there may be some 

cogeneration units that are determined to be covered under the 
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Boiler NESHAP. Such unit(s) may make a decision to increase the 

proportion of production output being supplied to the electric 

utility grid, thus causing the unit(s) to meet the EGU 

cogeneration criteria (i.e., greater than one-third of its 

potential output capacity and greater than 25 MW). In the 

preamble to the proposed rule, we indicated that 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 EGU NESHAP for the 6-month period after the unit meets the 

EGU definition.311 76 FR 25026. Assuming the EGU 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, or other applicable standard. We solicited 

comment on the extent to which situations like this might occur, 

how the EPA should address situations where units change 

applicability, and whether we should include provisions similar 

to those included in the final CISWI (40 CFR 60.2145) to address 

such situations. Id.

Several commenters asked the Agency to include provisions 

in the final rule that would address situations like the ones 

described in the preamble to the proposed rule. Because 

 

311 Although we clearly stated the intent to require sources to 

comply for 6 months after meeting the definition of an EGU, we 

inadvertently failed to include the provision in the proposed 

rule.
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applicability to the final rule is based in part on the 

statutory definition of an EGU is CAA section 112(a)(8), similar 

to the situation with units combusting solid waste under CAA 

section 129(g)(1) (e.g., CISWI Rule), we are adopting provisions 

in the final rule that are based on the fuel switching 

provisions of the final CISWI Rule (See Final CISWI Rule, 40 CFR 

60.2145). For example, a cogeneration unit that did not 

historically provide more than one third of its potential 

electrical output capacity to a power distribution system could 

change its output and provide more than 25 megawatts electrical 

output to any power distribution system for sale. Such units 

would be subject to MATS. If the cogeneration unit later reduced 

its output such that it no longer met the definition of an EGU, 

that source would nevertheless remain subject to MATS for at 

least 6 months from the date that the unit first qualified as an 

EGU.

In addition, we are finalizing a provision whereby you may 

opt to remain subject to the provisions of this final rule, 

unless you combust solid waste, in which case you are a solid 

waste incineration unit subject to standards under CAA section 

129 (e.g., 40 CFR Part 60, subpart CCCC (New Source Performance 

Standards (NSPS) for Commercial and Industrial Solid Waste 

Incineration Units), or subpart DDDD (Emissions Guidelines (EG) 
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for Existing Commercial and Industrial Solid Waste Incineration 

Units)). We believe the provision to opt to remain subject to 

this final rule will ameliorate conditions where EGUs may 

potentially move between NESHAP on a relatively frequent basis. 

Notwithstanding the provisions of this final rule, an EGU that 

starts combusting solid waste is subject to standards under CAA 

section 129, and the unit remains subject to those standards 

until the unit no longer meets the definition of a solid waste 

incineration unit consistent with the provisions of the 

applicable CAA section 129 standards.

The changes to the definitions described above provide 

clarity to sources, permitting agencies, and the public about 

the applicability of the rule and help ensure that sources are 

appropriately covered by the regulation.

B. Subcategories

In this final rule, the EPA is adding subcategories for 

limited-use oil-fired units and non-continental oil-fired units 

and revising the definitions for the coal-fired EGU 

subcategories.

The proposed rule subcategorized EGUs burning coal into two 

subcategories: EGUs designed for coal >8,300 Btu/lb and EGUs 

designed for virgin coal <8,300 Btu/lb (low rank virgin coal). 

We received a number of comments indicating that the definition 
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of the low rank virgin coal subcategory was technically 

deficient.

Under CAA section 112(d)(1), the Administrator has the 

discretion to “...distinguish among classes, types, and sizes of 

sources within a category or subcategory in establishing...”

standards. The EPA maintains that, normally, any basis for 

subcategorization (i.e., class, type, or size) must be related 

to an effect on HAP emissions that is due to the difference in 

class, type, or size of the units. See 76 FR 25036-25037. The 

EPA believes it is not reasonable to exercise our discretion 

without such a difference because if sources can achieve the 

same level of emissions reductions notwithstanding a difference 

in class, type, or size, the purposes of CAA section 112 are 

better served by requiring a similar level of control for all 

such units in the category or subcategory. See Lignite Energy 

Council v. EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999) (“EPA is not 

required by law to subcategorize--section 111 [b] [2] merely 

states that ‘the Administrator may distinguish among classes, 

types, and sizes within categories of new sources’” (emphasis 

original)); see also CAA section 112(d)(1) (containing almost 

identical language to CAA section 111, CAA section 112(d)(1) 

provides that “the Administrator may distinguish among classes, 

types, and sizes of sources within a category or subcategory in 
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establishing [] standards...”). Even if we determine that 

emissions characteristics are different for units that differ in 

class, type, or size, the Agency may still decline to 

subcategorize if there are compelling policy justifications that 

suggest subcategorization is not appropriate. Id. 

When developing the proposed rule, we examined the EGUs in 

the top performing 12 percent of sources for Hg emissions. We 

determined that:

There were no EGUs designed to burn a nonagglomerating 

virgin coal having a calorific value (moist, mineral 

matter-free basis) of 19,305 kJ/kg (8,300 Btu/lb) or 

less in an EGU with a height-to-depth ratio of 3.82 or 

greater among the top performing 12 percent of sources 

for Hg emissions, indicating a difference in the 

emissions for this HAP from these types of units. The 

boiler of a coal-fired EGU designed to burn coal with 

that heat value is bigger than a boiler designed to 

burn coals with higher heat values to account for the 

larger volume of coal that must be combusted to 

generate the desired level of electricity. Because the 

emissions of Hg are different between these two 

subcategories, we are proposing to establish different 

Hg emission limits for the two coal-fired 
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subcategories. For all other HAP from these two 

subcategories of coal-fired units, the data did not 

show any difference in the level of the HAP emissions 

and, therefore, we have determined that it is not 

reasonable to establish separate emissions limits for 

the other HAP. 76 FR 25036-67.

Based on this determination, we proposed to establish two 

subcategories with separate Hg limits. Comments on the proposed 

rule indicate that we correctly identified the EGUs that should 

be included in each subcategory, but the comments also 

demonstrated that we made certain incorrect conclusions that 

require us to revise the definitions of our coal-fired EGU 

subcategories. The revised definitions ensure that the EGUs we 

identified at proposal as having different Hg emissions remain 

in one subcategory.

As stated above, we believed at proposal that the boiler 

size was the cause of the different Hg emissions characteristics 

that led us to propose subcategorization, but many commenters 

indicated that it was not the boiler size but the fact that the 

EGUs burned a nonagglomerating virgin coal having a calorific 

value (moist, mineral matter-free basis) of less than 19,305 

kJ/kg (8,300 Btu/lb) (low rank virgin coal) that causes the 

disparity in Hg emissions. Several commenters indicated that 
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their EGUs were designed to burn and burned low rank virgin coal 

but the units did not meet the height-to-depth ratio that EPA 

proposed. For example, the height-to-depth ratio of certain EGUs 

in this subcategory is in fact 3.5, not 3.82. Further, there are 

other EGUs in this subcategory that are circulating fluidized 

bed (CFB) combustion units which do not meet the height-to-depth 

ratio parameters in the proposed rule, nor are they anything 

like the pulverized coal (PC) EGUs we initially identified as 

having the 3.82 height-to-depth ratio. 

In addition to the comments concerning EGUs firing this 

coal, we received comments from at least two commenters 

indicating that the EPA should clarify in which subcategory a 

unit belongs when it does not burn low rank virgin coal but is 

designed to combust low rank virgin coal and has a height-todepth ratio of greater than 3.82. Commenters also indicated that 

CFB units that are burning coal-refuse312 or other 

nonagglomerating virgin coal having a calorific value (moist, 

mineral matter-free basis) of 19,305 kJ/kg (8,300 Btu/lb) or 

greater are “designed to burn” any type of coal. Owners of CFB 

units that are not firing low rank virgin coal asked which 

subcategory they belong to based on their ability to burn any 

 

312 It is our understanding that no unit combusts coal-refuse 

from nonagglomerating virgin coal having a calorific value 

(moist, mineral matter-free basis) of less than 19,305 kJ/kg 

(8,300 Btu/lb).
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type of coal (including low rank virgin coal) without 

modification. These commenters also indicated that some coal 

refuse that is combusted has a heating value less than 8,300 

Btu/lb but is not “virgin coal.” It was unclear to which 

subcategory they belonged since the proposed rule did not in 

fact require the unit to burn any specific coal, instead only 

requiring the unit be “designed” to burn lower Btu coal. 

Based on the comments received, we reevaluated the 

subcategory definitions because we were concerned that the 

definitions we proposed would improperly categorize a number of 

the EGUs in both subcategories. We concluded that we should not 

maintain the proposed definition for “[u]nits designed for coal 

<8,300 Btu/lb” and exclude the CFB units and PC EGUs with a 

height-to-depth ratio less than 3.82 that combusted low rank 

virgin coal. 

We were equally concerned that the subcategory definitions 

not be revised in a manner that would move EGUs that we believed 

the data show could comply with a more stringent standard into a 

subcategory with a less stringent standard because, aside from 

the type of EGUs we identified, all other classes, types, and 

sizes of EGUs were represented among the top performing 12

percent for Hg in the >8,300 Btu/lb subcategory. We were 

particularly concerned about the CFB units because other CFB 
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units are well represented among the best performing EGUs for Hg

in the >8,300 Btu/lb subcategory, but the CFB units burning low 

rank virgin coal are not achieving the same levels of Hg 

emissions control. Including the best performing CFB units from 

the other subcategory in the low rank virgin coal subcategory 

would likely lead to a Hg standard as stringent as the standard 

for EGUs in the >8,300 Btu/lb subcategory because the CFB units 

from the other subcategory would be used to establish the floor. 

We believe that result would be inconsistent with the intent of 

the proposed rule. We were also concerned about the information 

that some EGUs that fired low rank virgin coal had a height-todepth ratio of 3.5, not 3.82, and that some EGUs that fired 

other ranks of coal had a height-to-depth ratio greater than 

3.82. For these reasons, we did not revise the definition to 

include CFB units and PC EGUs with a height-to-depth ratio 

greater than 3.5.

After fully considering the available information, 

including the comments received, we have concluded that it is 

appropriate to continue to base the subcategory definitions, at 

least in part, on whether the EGUs were designed to burn and, in 

fact, did burn low rank-virgin coal, but that it is not 

appropriate to continue to use the height-to-depth ratio 

criteria because that approach would potentially exclude EGUs we 
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identified as having different Hg emission characteristics and 

include EGUs that did not have different emissions 

characteristics. We recognize that some commenters have taken 

the position that it is unlawful to subcategorize based on 

factors such as fuel type but nothing in the statute prohibits

such an approach and the case law supports this approach to the 

extent courts have considered subcategorization based on such 

factors. See Sierra Club v. Costle, 657 F. 2d 298, 318-19 (D.C. 

Cir. 1981) (differing pollutant content of input material can 

justify a different standard based on subcategorization 

authority to “distinguish among classes, types and sizes within 

categories of new sources”). Furthermore, we believe had 

Congress intended to prohibit the EPA from subcategorizing based 

on an EGU being designed to use and using a certain material 

input (e.g., fuel) it would have clearly stated such intent in 

the CAA. However, we believe the Agency could decline to 

exercise its discretion to subcategorize even if the potential 

result would be the prohibition of the use of some materials if 

the circumstances warranted. We note that even if we did not 

subcategorize on the final basis selected, the Hg emissions 

standard of 1.2E0 lb/Tbtu for the “unit designed for coal >8,300 

Btu/lb” would remain the same.

We considered basing the subcategory solely on an EGU being 
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designed to burn and burning low rank virgin coal. We decided 

not to do so because we were concerned that such a definition 

would allow sources to potentially meet the definition by 

combusting very small amounts of low rank virgin coal. For 

example, an EGU on the east coast (or any other region) that was 

not designed to burn and did not routinely burn low rank virgin 

coal could import one truck full of low rank virgin coal and 

burn a very small quantity of it periodically to meet the 

subcategory definition. To avoid creating this potential 

loophole, we considered other characteristics that would 

distinguish EGUs combusting low rank virgin coal. 

We determined that these EGUs are universally constructed 

“at or near” a mine containing low rank virgin coal because it 

is not cost-effective to transport large quantities of such fuel 

long distances. Furthermore, we believe that this subcategory of 

EGUs are almost always built at a mine and limited 

transportation of the coal is only required as the mine face 

moves over the course of time. Many such EGUs construct 

dedicated rail lines, private roads, or conveyor systems to 

transport the coal to the EGU as the mine face moves. We 

obtained information from data acquired to develop the CSAPR 

indicating that the longest distance any EGU firing low rank

virgin coal transports that coal is 40 miles. We believe that 
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this distance is near the outer limits for the transport of such 

coal, but, even for those EGUs, the EGUs were constructed closer 

to a now idle mine or closer to the working face of a mine that 

has now expanded away from the EGU site. For these reasons, we 

are including a requirement that the unit be constructed and 

operated at or near a mine containing the low rank virgin coal

it burns.

We are revising the coal-fired EGU subcategory definitions 

as follows:

Unit designed for low rank virgin coal is an coalfired EGU designed to burn and is burning 

nonagglomerating virgin coal having a calorific value 

(moist, mineral matter-free basis) of less than 19,305 

kJ/kg (8,300 Btu/lb) that is constructed and operates 

at or near the mine that produces such coal.

Unit designed for coal >8,300 Btu/lb means any coalfired EGU that is not an EGU in the “low rank virgin 

coal” subcategory.

We believe the revised subcategory definitions are 

reasonable for all the reasons set forth above. The revised 

definitions maintain the EGUs we identified as having different 

Hg emissions characteristics in one subcategory and the 

definitions prevent other EGUs that are not firing low rank 
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virgin coal from being required to comply only with the less 

stringent Hg emission standard. 

As discussed in response to comments, we do not believe 

that additional subcategorization of other coal-fired EGUs is 

reasonable or appropriate. All other coal-fired EGUs that are 

not designed to burn and are burning low rank virgin coal are 

represented among the best performing sources for Hg, such that 

no argument exists to support that the Hg emissions from those 

EGUs are different. In any case, even if emissions are somewhat 

different as some commenters suggest, we would decline to 

exercise our discretion because the data demonstrate that the 

best performing EGUs designed to burn and burning all other 

ranks of coal are able to achieve the MACT level of control

using currently available controls and other HAP emission 

reduction mechanisms (e.g., coal washing) for the >8,300 Btu/lb 

subcategory.

A second issue related to subcategorization concerns noncontinental liquid oil-fired EGUs. At proposal, the EPA did not 

have sufficient emissions data from non-continental liquid oilfired EGUs upon which to base a subcategory and took comment on 

the issue. The data have since been provided in response to the 

ICR and we received comments suggesting that a non-continental 

subcategory is appropriate based on the location of such units, 
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the limited availability of alternative fuel sources, and the 

fact that the emissions characteristics of such units are 

distinct from continental liquid oil-fired EGUs. The EPA has 

evaluated the data and comments and we agree that a subcategory 

is warranted based for the reasons suggested by the commenters. 

Therefore, the Agency is finalizing the liquid oil-fired EGU 

subcategories of “continental” and “non-continental.”

Lastly, the EPA did not have sufficient information on 

limited-use liquid oil-fired EGUs upon which to base a 

subcategory at proposal because some sources required to test 

under the ICR did not submit the data until after proposal. We

took comment on whether a limited-use subcategory was warranted. 

Commenters indicated that their units were a different class and 

type of units because many of them were only called to service 

to address reliability issues associated with, for example, 

natural gas curtailments. The commenters further indicated that 

their units are different because of the generally infrequent 

use and the sporadic, and at times frequent, start-up and 

shutdown periods (e.g., they are often only required to run for 

a couple of hours). These factors would lead to differences in 

the emissions characteristics for these units such that a 

numeric standard based on base load units would not likely be 

achievable during the very limited times that these limited use 
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oil-fired units operate. Based on comments received and our own 

analysis, we are finalizing a subcategory for limited-use liquid 

oil-fired EGUs as discussed further elsewhere in this preamble.

C. Emission Limits

The proposed rule included numerical emission limits for 

PM, Hg, HCl, HF, SO2, total HAP metals, and individual HAP 

metals, depending on the subcategory and specific situation. 

These proposed limits resulted from calculations of MACT floors 

using information and data available to the Agency prior to 

proposal, as required by CAA section 112. Based on information 

and data received during the comment period, we have made data 

and calculation corrections where necessary and then re-ranked 

the best performing units in the MACT floor pools. Based on the 

new ranking, a limited number of the emission limits in the 

final rule have changed from those proposed.

In addition to adjustments to the emission limits 

themselves, we are finalizing several other changes to the 

emission standards that will simplify and improve compliance for 

sources without compromising the toxics reductions achieved. One 

key change, as discussed elsewhere in this notice, is that we 

have changed the surrogate for non-mercury metallic HAP from 

total particulate matter (PM) to filterable PM for coal-fired 

and solid oil-derived EGUs. This change is based on information 
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provided in comments and our own conclusion that measurement of 

filterable PM provided assurance of equivalent HAP emissions 

control. Most of the non-mercury metal HAP, for which PM is a 

surrogate, are filterable PM and the one that is not (Se) is 

well controlled by the limit on acid gases. Using filterable PM 

as the surrogate will allow us to use continuous PM monitoring 

systems, which measure filterable (but not total) PM, thereby 

providing a more continuous measure of compliance.

For liquid oil-fired EGUs, based on comments received and 

corrections made to the data submitted, we have added a 

filterable PM limit in the final rule as an alternative 

equivalent standard for the total metal-HAP limit in the 

proposed rule. In addition, as discussed elsewhere in this 

notice, we have added measurement of the moisture content of the 

oil (with a 1 percent limit) as an alternate compliance 

assurance measure for liquid oil-fired EGUs for determining 

compliance with the HCl and HF limits. Direct measurement of HCl 

and HF remains a compliance demonstration method in the final 

rule. Finally, as discussed in section VI.D of this notice, the 

final work practice standard consisting of burner tune-ups, much 

like those required for organic HAP control, for those limiteduse liquid oil-fired EGUs whose annual capacity factor is less 

than 8 percent.
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D. Work Practice Standards for Organic HAP Emissions

As noted earlier in section V.D., the final rule includes a 

work practice standard for organic HAP, including dioxins and 

furans, applicable to all EGUs. As noted in section V.D. above, 

the majority of emissions of these pollutants are below the 

detection levels of EPA test methods and, therefore, are 

impractical to measure. The work practice standard, described 

below, is a practical approach to ensuring that equipment is 

maintained and run so as to minimize emissions of dioxins and 

furans, and we expect it to be more effective than establishing 

a numeric standard that cannot reliably be measured or 

monitored. The work practice also applies to the limited-use 

liquid oil-fired subcategory included in the final rule.

The work practice involves maintaining and inspecting the 

burners and associated combustion controls (as applicable), 

tuning the specific burner type to optimize combustion, 

obtaining and recording CO and NOX values before and after the 

burner adjustments, keeping records of activity and 

measurements, and submitting a report for each tune-up 

conducted. In Table 3 of the final regulation, we have clarified 

that this refers to performance tune-ups, not tests, and have 

addressed the frequency requirement as discussed in response to 

comments about the appropriateness of the 18-month frequency. 
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The provisions of 40 CFR section 63.10006(h)(i) refer to 40 CFR 

section 63.10021(e) for the specific steps required to be part 

of the periodic tune-up. We have also adjusted the language in 

the final rule to recognize the value of automated boiler 

optimization tools such as neural network systems.

Under the final rule, the tune-up must be conducted at each 

planned major outage and in no event less frequently than every 

36 calendar months, with an exception that if the unit employs a 

neural-network system for combustion optimization during hours 

of normal unit operation, the required frequency is a minimum of 

once every 4 years (48 calendar months). Initial compliance with 

the work practice standard of maintaining burners must occur 

within 180 days of the compliance date of the rule. The initial 

compliance demonstration for the work practice standard of 

conducting a tune-up may occur prior to the compliance date of 

the rule, but must occur no later than 42 months (36 months plus 

180 days) from the compliance date of the rule or, in the case 

of units employing neural network combustion controls, 54 months 

(48 months plus 180 days). If the tune-up occurs prior to the 

compliance date of the rule, you must maintain adequate records 

to show that the tune-up met the requirements of this standard.

We have made a number of specific changes to address what 

to do for repairs that may require longer term corrective 
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actions, additional methods for evaluating combustion 

effectiveness, and clarification on procedures for recording CO 

and NOX information. There were specific comments that opposed 

the reference to manufacturer specifications, if available. We 

retained this language in the final rule, but note that these 

specifications apply only to the extent applicable. 

Specifically, if manufacturer specifications only address 

equipment or conditions that are no longer present given current 

boiler operations, then those specifications are not applicable 

and other combustion engineering best practice procedures for 

that burner type would apply. We have also clarified that 

portable emission monitoring equipment may be used to collect 

the required emissions optimization data regarding pre- and 

post-tune-up CO and NOX emission levels.

E. Requirements during Startup, Shutdown, and Malfunction

We proposed numerical emission standards that would apply 

at all times, including during periods of startup, shutdown, and 

malfunction. Although at proposal we stated that we were not 

setting a different standard for startup and shutdown, we did 

propose different standards for startup and shutdown by our 

inclusion of the default values described below, which applied 

only during startup and shutdown. Specifically, we stated:

To appropriately determine emissions during startup 
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and shutdown and account for those emissions in 

assessing compliance with the proposed emission 

standards, we propose use of a default diluent value 

of 10.0 percent O2 or the corresponding fuel specific 

CO2 concentration for calculating emissions in units of 

lb/MMBtu or lb/TBtu during startup or shutdown 

periods. For calculating emissions in units of lb/MWh 

or lb/GWh, we propose source owners use an electrical 

production rate of 5 percent of rated capacity during 

periods of startup or shutdown. We recognize that 

there are other approaches for determining emissions 

during periods of startup and shutdown, and we request 

comment on those approaches. We further solicit 

comment on the proposed approach described above and 

whether the values we are proposing are appropriate.

We proposed application of the respective emission limits 

during periods of startup and shutdown and use of default values 

to calculate the emission limits. The standards that apply at 

all times other than startup and shutdown are production-based 

limits, which is why we proposed the default values. The default 

values were meant to account for the fact that during startup 

and shutdown events, production (in this case the generation of 

electricity) is by definition nonexistent. Thus, in effect, we 
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proposed a separate standard to apply during startup and 

shutdown.

We received a variety of comments on the proposed standards 

that would apply during startup and shutdown. Many commenters 

pointed to the lack of data in the record concerning emissions 

that occur during periods of startup and shutdown. They further 

asserted that emissions during these periods can be highly 

variable in light of the sequence of events that occurs during 

the startup and shutdown of an EGU. Although a number of 

commenters supported the use of the diluent factor approach, 

including the default 5 percent of rated capacity, during 

startup/shutdown periods, other commenters questioned the 

feasibility of collecting additional data during such periods 

and had concerns regarding the reliability of measurements 

obtained from EGUs during such periods.

In response to the Agency’s ICR to the utility industry, 

seven owners or operators indicated that they provided startup 

and shutdown data for their EGUs. These data were submitted in 

response to the requirement in the ICR to provide all available 

data from the 5 years prior to the date the ICR was issued. Of 

these data, there were almost no HAP data for startup and 

shutdown periods and almost all of the data failed to meet our 
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data quality requirements.313 Thus, we do not have sufficient data 

on emissions that occur during startup and shutdown on which to 

set emission standards. We are therefore establishing work 

practice standards rather than numeric emissions standards for 

periods of startup and shutdown in the final rule. Before we 

describe those work practices, we first address what constitutes 

startup and shutdown.

Several commenters had an expansive view of what 

constitutes startup and shutdown. We disagree with these 

commenters that asserted that periods of “load swings” should be 

considered “startup” or “shutdown,” as they are generally 

 

313 In response to the ICR, we also received SO2 CEMS data and the 

Agency had additional SO2 CEMS data available through the CAMD 

ARP database. We are not able to identify specific periods of 

start-up and shutdown in either the ICR CEMS data or the CAMD 

ARP data, and the ICR respondents do not indicate that the ICR 

data includes periods of startup and shutdown. We set the 

emission limits for SO2 and HCl using the data provided to the 

EPA from the 2010 ICR, not the CAMD data, since those data were 

taken concurrently under the same specified operating conditions 

using the same fuel. We used the SO2 CEMS data that was submitted 

in response to the ICR by converting it to single point data to 

correlate to the data from units that did not provide CEMS data 

from the relevant testing period. The emissions limits for the 

NESHAP incorporated variability by applying the 99 percent UPL 

to the average emissions developed from the stack test data and 

SO2 CEMS data that was converted to stack test data. Thus, we did 

not have data on which to establish an SO2 standard during 

periods of startup and shutdown and the numeric standards do not 

apply to those periods in the final rule. In contrast, the NSPS 

for SO2 is applicable during periods of startup and shutdown 

since the long term CAMD ARP CEMS data were used to determine 

the average performance of the best demonstrated technology. 

Those long term data were assumed to incorporate process 

variability including that associated with fuel and 

process/operational changes and periods of startup and shutdown.
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routine, normal operations with production (i.e., generation of 

electricity) taking place. We maintain that the standards as 

promulgated account for any variability in emissions that may 

occur during these periods over a 30-day averaging period, and 

commenters have provided no data that cause us to doubt that 

determination. We have included definitions of startup and 

shutdown in the final rule that are consistent with the 

definitions in the proposed rule. At proposal, we included the 

following definitions of startup and shutdown:

Startup means the setting in operation of an affected 

source or portion of an affected source for any 

purpose.

Shutdown means the cessation of operation of an 

affected source or portion of an affected source for 

any purpose.

Commenters sought more clarity regarding the meaning of 

these terms as applied to EGUs, so we are revising the 

definitions in the final rule as follows. 

Startup means either the first-ever firing of fuel in 

a boiler for the purpose of producing electricity, or 

the firing of fuel in a boiler after a shutdown event 

for any purpose. Startup ends when any of the steam 

from the boiler is used to generate electricity for 
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sale over the grid or for any other purpose (including 

on site use).

Shutdown means the cessation of operation of a boiler 

for any purpose. Shutdown begins either when none of 

the steam from the boiler is used to generate 

electricity for sale over the grid or for any other 

purpose (including on-site use) or at the point of no 

fuel being fired in the boiler, whichever is earlier.

Shutdown ends when there is both no electricity being 

generated and no fuel being fired in the boiler.

These interpretations are tailored for EGUs and are 

consistent with the definitions of “startup” and “shutdown”

contained in the 40 CFR Part 63, subpart A General Provisions. 

We believe these revised definitions address the comments and 

are rational based on the fact that EGUs function to provide

electricity primarily for sale to the grid but also at times for 

use on-site; therefore, EGUs should be considered to be 

operating normally at all times electricity is generated. We 

further believe these revised definitions address what some 

commenters describe as “warm” and “hot” startups as long as the 

EGU is shutdown (i.e., no fuel fired and no electricity 

generation) prior to the “warm” or “hot” startup period.

As for the work practices, in this final rule, the EPA is 
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requiring sources to operate using either natural gas or 

distillate oil for ignition during startup. The EPA also is 

requiring sources to vent emissions to the main stack(s) and 

operate all control devices necessary to meet the normal 

operating standards under this final rule (with the exception of 

dry scrubbers and SCRs) when coal, solid oil-derived fuel, or 

residual oil is fired in the boiler during startup or shutdown. 

It is the responsibility of the operators of EGUs to start their 

dry scrubber and SCR systems appropriately to comply with 

relevant standards applicable during normal operation.

The EPA carefully considered fuels and potential 

operational constraints of air pollution control devices (APCDs) 

when designing its work practices for periods of startup and 

shutdown. The EPA notes that there is no technical barrier to 

burning natural gas or distillate oil for longer portions of 

startup or shutdown periods, if needed, at a boiler, and the HAP 

emission reduction benefits warrant additional utilization of 

such fuels until the temperature and stack emissions pressure is 

sufficient to engage the APCDs. The EPA is aware that SCR 

systems with ammonia injection need to be operated within a 

prescribed and relatively narrow temperature window to provide 

NOX reductions. Further, the EPA is aware that dry scrubbers also 

need to be operated close to flue gas saturation temperature. 
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Because these devices have specific temperature requirements for 

proper operation, the EPA notes in its work practices that it is 

the responsibility of the operators of EGUs to start their SCR 

and dry scrubber systems appropriately to comply with relevant 

standards applicable during normal operation.

Some commenters have asserted that firing of fuel oil 

during periods of startup and shutdown constrains operation of 

PM controls (ESPs and baghouses) because under cooler 

conditions, acids and tars can condense on surfaces in these 

controls. The commenters assert that such condensation can cause 

detrimental impacts on hardware and operation of these controls, 

and could cause safety concerns. The EPA understands that 

concerns with acidic and tarry deposits are related to firing of 

heavy (residual) oil and not distillate oil. Accordingly, with 

residual fuel oil firing, site-specific flue gas temperature and 

oxygen (O2) concentration thresholds may be applicable to 

minimize condensation of acids and tars and thereby minimize any 

potential for detrimental impacts on hardware and any safety 

concerns. However, the EPA notes that its work practice 

requirements provide flexibility to the operator to take 

appropriate site-specific remedial measures, if needed. The EPA

further notes that boilers have several options to prevent 

detrimental impacts by: (1) using startup fuels, natural gas or 
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distillate oil, until appropriate flue gas conditions have been 

reached and then fire residual oil; (2) pre-coating the PM 

control surfaces314 with an alkaline powder (e.g., limestone);

(3) installing chemically resistant bags315 in baghouses if 

applicable; and (4) using low-sulfur oils. The EPA also notes 

that currently the industry has many operational residual oilfired boilers that are started up with either natural gas or 

distillate fuel oil. At these boilers, the transition from the 

startup fuel, distillate oil or natural gas, to residual oil is 

already being practiced without unacceptable impacts on APCDs

including PM controls, which are operated to meet applicable 

opacity limits. Based on this experience and the options 

described above, those boilers where residual oil is used for 

either a part of the startup period, or as the main fuel, will 

also be able to operate their PM controls to meet the work 

practice requirements of the rule. Note that coal firing is done 

at high enough temperatures that concerns with condensation are 

not relevant. None of the commenters have specifically commented 

on this aspect of coal firing.

The EPA is not aware of any operational constraints 

 

314 Coal Power, May 1, 2007: 

http://www.coalpowermag.com/plant_design/Coal-Plant-O-and-MRiver-Locks-and-Barges-Are-an-Aging-Workforce-Too_36.html

315 Neundorfer: Lesson #4, p.4-7, Table 4-1: 

http://www.neundorfer.com/FileUploads/CMSFiles/Fabric%20Filter%2

0Material[0].pdf
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applicable to operation of wet scrubbers during startup that 

could cause detrimental impacts on wet scrubber hardware and 

safety concerns and none of the commenters have commented on 

this aspect of wet scrubber operation. 

Finally, the EPA notes that dry sorbent injection (DSI) can 

be applied across a very broad temperature range and will be 

engaged when residual oil or coal is fired in a boiler to comply 

with HCl requirements. Again, no comments have been received on 

this aspect of DSI operation.

This final rule requires work practice standards for 

emissions during startup and shutdown, and the rule requires 

sources to measure and report their emissions at all times, 

including periods of startup and shutdown, when continuous 

monitoring is used to demonstrate compliance. Data collected 

under this final rule will provide the EPA with information to 

more fully analyze this issue and address it during the 8-year 

review established under CAA section 112.

We now address malfunctions. In contrast to the exclusion 

of startup and shutdown period emissions from 30-boiler 

operating day rolling average emissions, the final rule requires 

inclusion of emissions during periods of source or APCD 

malfunction. We have concluded that when combined with the 

availability of an affirmative defense as described below, this 
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is an appropriate and practical approach.

As mentioned earlier, 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). The EPA has determined that CAA 

section 112 does not require that emissions that occur during 

periods of malfunction be factored into development of CAA 

section 112 standards. Under CAA section 112, emissions 

standards for new sources must be no less stringent than the 

level “achieved” by the best controlled similar source and for 

existing sources generally must be no less stringent than the 

average emission limitation “achieved” by the best performing 12 

percent of sources in the category. There is nothing in CAA 

section 112 that directs the Agency to consider malfunctions in 

determining the level “achieved” by the best performing or best 

controlled sources when setting emission standards. Moreover, 

while the EPA accounts for variability in setting emissions 

standards consistent with the CAA section 112 case law, nothing 

in that case law requires the Agency to consider malfunctions as 

part of that analysis. Clean Air Act section 112 uses the 
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concept of “best controlled” and “best performing” unit in 

defining the level of stringency that CAA section 112 

performance standards must meet. Applying the concept of “best 

controlled” or “best performing” to a unit that is 

malfunctioning presents significant difficulties, as 

malfunctions are sudden and unexpected events.

Further, accounting for malfunctions would be difficult, if 

not impossible, given the myriad different types of malfunctions 

that can occur across all sources in the category and given the 

difficulties associated with predicting or accounting for the 

frequency, degree, and duration of various malfunctions that 

might occur. As such, the performance of units that are 

malfunctioning is not “reasonably” foreseeable. See, e.g., 

Sierra Club v EPA, 167 F. 3d 658, 662 (D.C. Cir. 1999) (The EPA 

typically has wide latitude in determining the extent of datagathering necessary to solve a problem. We generally defer to an 

agency’s decision to proceed on the basis of imperfect 

scientific information, rather than to “invest the resources to 

conduct the perfect study.”). See also, Weyerhaeuser v Costle, 

590 F.2d 1011, 1058 (D.C. Cir. 1978) (“In the nature of things, 

no general limit, individual permit, or even any upset provision 

can anticipate all upset situations. After a certain point, the 

transgression of regulatory limits caused by ‘uncontrollable 
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acts of third parties,’ such as strikes, sabotage, operator 

intoxication or insanity, and a variety of other eventualities, 

must be a matter for the administrative exercise of case-by-case 

enforcement discretion, not for specification in advance by 

regulation.”). In addition, the goal of a best controlled or 

best performing source is to operate in such a way as to avoid 

malfunctions of the source and accounting for malfunctions could 

lead to standards that are significantly less stringent than 

levels that are achieved by a well-performing non-malfunctioning 

source. The EPA’s approach to malfunctions is consistent with 

CAA section 112, and we believe it is a reasonable 

interpretation of the statute. This approach to malfunctions has 

been used consistently in CAA section 112 and CAA section 129 

rulemaking actions since the D.C. Circuit’s decision in Sierra 

Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008)vacated the SSM 

exemption contained in CFR 63.6(f)(1) and 40 CFR 63.6(h)(1). 

(See, e.g., National Emission Standards for Hazardous Air 

Pollutants From the Portland Cement Manufacturing Industry and 

Standards of Performance for Portland Cement Plants, 75 FR 54970 

(September 9, 2010); Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: Sewage 

Sludge Incineration Units; Final Rule, 76 FR 15372 (March 21, 

2011).
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In the event that a source fails to comply with the 

applicable CAA section 112(d) standards as a result of a 

malfunction event, the 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. The 

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 section 63.2 (definition of malfunction).

Finally, the EPA recognizes that even equipment that is 

properly designed and maintained can sometimes fail and that 

such failure can sometimes cause an exceedance of the relevant 

emission standard. (See, e.g., State Implementation Plans: 

Policy Regarding Excessive Emissions During Malfunctions, 

Startup, and Shutdown (Sept. 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, Maintenance, and 

Malfunctions (Feb. 15, 1983)). The EPA is therefore adding to 

the final rule an affirmative defense to civil penalties for 

exceedances of emission limits that are caused by malfunctions. 

See 40 CFR 63.10042 (defining “affirmative defense” to mean, in 
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the context of an enforcement proceeding, a response or defense 

put forward by a defendant, regarding which the defendant has 

the burden of proof, and the merits of which are independently 

and objectively evaluated in a judicial or administrative 

proceeding). We also have added other regulatory provisions to 

specify the elements that are necessary to establish this 

affirmative defense; the source must prove by a preponderance of 

the evidence that it has met all of the elements set forth in 

63.10001. (See 40 CFR 22.24). The criteria ensure that the 

affirmative defense is available only where the event that 

causes an exceedance of the emission limit meets the narrow 

definition of malfunction in 40 CFR 63.2 (i.e., sudden, 

infrequent, not reasonable preventable and not caused by poor 

maintenance and or careless operation). For example, to assert 

the affirmative defense successfully, the source must prove by a 

preponderance of the evidence that excess emissions “[w]ere 

caused by a sudden, infrequent, and unavoidable failure of air 

pollution control and monitoring equipment, process equipment, 

or a process to operate in a normal or usual manner...” The 

criteria also are designed to ensure that steps are taken to 

correct the malfunction, to minimize emissions in accordance 

with section 63.10001 and to prevent future malfunctions. For 

example, the source must prove by a preponderance of the 
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evidence that “[r]epairs were made as expeditiously as possible 

when the applicable emission limitations were being exceeded...”

and that “[a]ll possible steps were taken to minimize the impact 

of the excess emissions on ambient air quality, the environment 

and human health...” In any judicial or administrative 

proceeding, the Administrator may challenge the assertion of the 

affirmative defense and, if the respondent has not met its 

burden of proving all of the requirements in the affirmative 

defense, appropriate penalties may be assessed in accordance 

with CAA section 113 (see also 40 CFR Part 22.27). 

The EPA is including an affirmative defense in the final 

rule as we have in other recent MACT rules so as to balance the

tension, inherent in many types of air regulation, to ensure 

adequate compliance while simultaneously recognizing that 

despite the most diligent of efforts, emission limits may be 

exceeded under circumstances beyond the control of the source. 

The EPA must establish emission standards that “limit the 

quantity, rate, or concentration of emissions of air pollutants 

on a continuous basis.” 42 U.S.C. §7602(k)(defining “emission 

limitation and emission standard”). See generally Sierra Club v. 

EPA, 551 F.3d 1019, 1021 (D.C. Cir. 2008). Thus, the EPA is 

required to ensure that section 112 emissions limitations are 

continuous. The affirmative defense for malfunction events meets 
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this requirement by ensuring that even where there is a 

malfunction, the emission limitation is still enforceable 

through injunctive relief. While “continuous” limitations, on 

the one hand, are required, there is also case law indicating 

that in some situations it is appropriate for the EPA to account 

for the practical realities of technology. For example, in Essex 

Chemical v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the 

D.C. Circuit acknowledged that in setting standards under CAA 

section 111 “variant provisions” such as provisions allowing for 

upsets during startup, shutdown and equipment malfunction 

“appear necessary to preserve the reasonableness of the 

standards as a whole and that the record does not support the 

‘never to be exceeded’ standard currently in force.” See also, 

Portland Cement Association v. Ruckelshaus, 486 F.2d 375 (D.C. 

Cir. 1973). Though intervening case law such as Sierra Club v. 

EPA and the CAA 1977 amendments calls into question the 

relevance of these cases today, they support the EPA’s view that 

a system that incorporates some level of flexibility is 

reasonable. The affirmative defense simply provides for a 

defense to civil penalties for excess emissions that are proven 

to be beyond the control of the source. By incorporating an 

affirmative defense, the EPA has formalized its approach to 

upset events. In a Clean Water Act setting, the Ninth Circuit 
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required this type of formalized approach when regulating 

“upsets beyond the control of the permit holder.” Marathon Oil 

Co. v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977). But see, 

Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 

1978) (holding that an informal approach is adequate). The 

affirmative defense provisions give the EPA the flexibility to 

ensure both that its emission limitations are “continuous” as 

required by 42 U.S.C. §7602(k), and account for unplanned upsets 

and thus support the reasonableness of the standard as a whole.

F. Testing and Initial Compliance

We have carefully evaluated the wide-ranging comments on 

testing, continuous monitoring, and other provisions regarding 

initial compliance demonstrations, and we have made adjustments 

intended to help streamline implementation while still ensuring 

adequate demonstration of compliance with the emission limits 

and other standards established under this final rule. The 

significant changes include:

1. No fuel analysis requirements

Apart from an alternative that allows you to analyze fuel 

moisture for liquid oil-fired EGUs rather than measuring HCl and 

HF, the final rule does not include any of the fuel analysis 

requirements that were in the proposed rule, either as part of 

initial compliance demonstrations or ongoing compliance 
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demonstrations. In reviewing the results of the fuel analyses 

and the expected range of results that would be received from 

laboratories conducting the proposed analyses, we determined 

that too many results would be returned as “below detection 

level” and, thus, provide little information to assist with rule 

implementation and compliance oversight. Given the costs and 

efforts involved, we determined that the proposed fuel analysis 

requirements would not be an effective compliance monitoring 

tool for this final rule.

2. Clarification of testing

We have clarified that where options for emission limits 

apply (such as filterable PM versus non-mercury HAP metals, or 

SO2 versus HCl), you need only perform stack testing to 

demonstrate compliance with the selected emission limit. For 

example, if you elect to meet the individual non-mercury HAP 

metals standards, you must conduct the Method 29 test for the 

metals, and you do not have to conduct a Method 5 test for PM. 

3. Low Emitting EGU qualification

We have significantly modified the proposed requirements to 

qualify as a LEE unit for a pollutant other than Hg based on an 

initial performance test. Under the proposed rule, the operating 

limit monitoring provided additional assurance of compliance for 

a source qualified for non-mercury LEE status based on an 
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initial compliance demonstration. Under the final rule, to 

qualify for LEE status for pollutants other than Hg, a unit must 

meet the LEE criteria for a series of performance tests over a 

3-year period to demonstrate that the unit continues to perform 

well below the standard for which the source has obtained LEE 

status.

G. Continuous Compliance

The most significant changes to the testing and monitoring 

requirements involve the procedures for demonstrating continuous 

compliance. The proposed rule contained different options 

involving CEMS, periodic stack tests, fuel analysis, and various 

PM and control device operating limits. The final rule greatly 

simplifies the requirements and provides two basic approaches 

for most situations: use of continuous monitoring (either CEMS 

or PM continuous parametric monitoring system, CPMS) or periodic 

quarterly testing. The final rule does not contain the proposed 

fuel analysis requirements. For periodic testing, the proposed 

rule required testing every month or every 2 months. For those 

EGU owners or operators who choose to use emissions testing to 

demonstrate compliance, the final rule requires quarterly

filterable PM or non-mercury metals HAP, whether individual or 

total metals, testing for coal- and liquid oil-fired units. The 

rule requires quarterly HCl testing for coal-fired units and 
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quarterly HCl and HF testing, along with site-specific

monitoring for liquid oil-fired units to ensure compliance with 

the HCl and HF standards. The final rule also has a separate 

compliance demonstration for those liquid oil-fired EGUs that 

have an annual capacity factor of less than 8 percent (emission 

limits do not apply, just the tune-up work practice standard).

For those EGU owners or operators who choose to use emissions 

testing to demonstrate compliance, the final rule requires 

quarterly filterable PM or non-mercury metals HAP, whether 

individual or total metals, testing for coal- and liquid oilfired units; quarterly HCl testing for coal-fired units and 

quarterly HCl and HF testing, along with site-specific parameter 

monitoring for liquid oil-fired units to ensure compliance with 

the HCl and HF standards. 

The continuous monitoring options remain generally intact 

from the proposed rule, with relatively minor clarifications 

concerning calculation of 30-boiler operating day averages and 

QA requirements.

The final rule eliminates all operating limits for PM 

except for the use of a PM CPMS. For the PM CPMS, the final rule 

clarifies procedures for setting this operating limit and how it 

is distinct from the PM emission limit. The PM CPMS will not be 

correlated as a PM CEMS under PS 11 and will produce data in 
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terms of a signal you define. That signal could be milliamps, 

stack concentration, or other output signal instead of PM 

emissions in units of the standard. The operating limit will be 

set using the highest hourly average obtained from the PM CPMS 

during the performance test. Compliance with the limit is based 

on a 30-boiler operating day rolling average basis. However, the 

final rule also does provide for the use of a PM CEMS to 

determine compliance with the filterable PM emission limit if 

the source elects to use this approach. The EPA believes that 

some sources may be interested in adopting this direct approach,

and so has included that option in the final rule. If this 

approach is selected, the PM CEMS is used as the direct method 

of compliance and no additional testing is required other than 

tests that are required as part of the QA requirements in PS 11

and Procedure 2. To use this option, the source must elect to 

meet the filterable PM standard, and not one of the HAP metals 

standards.

Apart from the operating limit for site-specific monitoring

associated with liquid oil-fired EGUs, we removed the other 

operating limits for control devices based on a review of the 

comments, after considering other programs in place to ensure 

proper operations of controls at EGUs. Those other programs 

include compliance assurance monitoring under Part 64, Part 70,
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and New Source Review permit conditions, and other SIP and NSPS 

requirements for operating and maintaining equipment in 

accordance with good air pollution control practices. Those 

requirements, in combination with the CEMS, PM CPMS, and 

frequent periodic testing provisions under the final rule, will 

enhance the monitoring of continuous compliance with the 

requirements of this rule.

Because the EPA is concerned that there will be little or 

no monitoring in these underlying applicable requirements for 

acid gases at liquid oil-fired EGUs, the final rule requires a 

site-specific monitoring plan for those units in this 

subcategory that demonstrate compliance with the HCl and HF 

standards through quarterly performance tests. With the 

exception for limited-use liquid oil-fired EGUs and other 

monitoring options available (such as fuel moisture monitoring 

or HCl/HF CEMS), the EPA believes this provision will apply to 

few units. The owner or operator will submit the site-specific 

plan to identify appropriate parameters that ensure that the 

operations of the unit critical to meeting the HCl/HF emission 

limits remain consistent with conditions during performance 

testing. This will be approved similarly to an alternative 

monitoring request. The plan should include the parameters, 

monitoring approach, QA/QC elements, and data reduction 
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(including averaging period) elements. Like the PM CPMS 

operating limit, the operating limit for acid gas control 

devices on liquid oil-fired EGUs will be set using the highest 

hourly average obtained during the HCl and HF performance tests. 

Compliance with the limit is based on a 30-boiler operating day 

rolling average basis.

Finally, we have changed the continuous compliance 

requirements for the performance tune-up work practice standard 

since the proposal. Our intent was that this work practice 

standard could be performed in conjunction with routine 

maintenance operations at a facility and be a logical extension 

of routine best practices for boiler inspection and 

optimization. Based on the comments received, we have reduced 

the required frequency for this inspection to every 3 years and 

provided incentives for neural network combustion management and 

optimization practices by providing a longer interval of 4 years 

between inspections when such systems are in use at a given EGU.

H. Emissions Averaging

We are finalizing that owners and operators of existing 

affected sources may demonstrate compliance by emissions 

averaging for existing EGUs that are located at the same 

facility that are within a single subcategory and that rely on 

emissions testing as the compliance demonstration method. In 
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response to our request for comments on the suitability of 

emissions averaging and need for a discount factor, we received 

a range of suggestions, including requests for clarification 

regarding eligibility, points for and against the need for a 

discount factor, and suggestions to ease implementation.

As we noted at proposal, part of the EPA’s general policy 

of encouraging the use of flexible compliance approaches where 

they can be properly monitored and enforced is to include 

emissions averaging. Emissions averaging can provide sources the 

flexibility to comply in the least costly manner while still 

maintaining a regulation that is workable and enforceable. 

Emissions averaging would not be applicable to new affected 

sources and could only be used between EGUs in the same 

subcategory at a particular facility. Also, owners or operators 

of existing sources subject to the EGU NSPS (40 CFR Part 60, 

subparts D and Da) would be required to continue to meet the PM 

emission standard of that NSPS regardless of whether or not they 

are using emissions averaging (i.e., an EGU subject to 40 CFR 

Part 60, subpart D or Da must meet its applicable NSPS 

filterable PM emission limit even if it is included in a 40 CFR 

Part 63, subpart UUUUU, emissions averaging group for filterable 

PM).

Emissions averaging allows owners and operators of a 
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facility that includes existing EGUs within a subcategory to 

demonstrate that the source complies with the proposed emission 

limits by averaging the emissions from an individual affected 

EGU that is emitting above the proposed emission limits with 

other affected EGUs at the same facility that are emitting below 

the proposed emission limits and that are within the same 

subcategory. Although some commenters note that the MACT limits 

are low, based on the data available to the Agency, we believe 

that dozens of existing EGUs are achieving all of the limits 

and, thus, emissions averaging is a possible approach.

The final rule includes an emissions averaging compliance 

alternative because emissions averaging316 represents an 

equivalent, more flexible, and less costly alternative to 

controlling certain emission points to MACT levels. We have 

concluded that averaging in the proposed rule could be 

implemented and that it would not lessen the stringency of the 

MACT floor limits and would provide flexibility in compliance, 

cost and energy savings to owners and operators. We also 

recognize that we must ensure that any emissions averaging 

option can be implemented and enforced, will be clear to 

sources, and most importantly, will be no less stringent than 

unit-by-unit implementation of the MACT floor limits.

 

316 As long as required emission rates are designed to account 

for factors such as changes in averaging times.
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In the final rule, the EPA is providing that sources may 

average emissions from existing EGUs at the same facility and 

within the same subcategory. Further, for Hg emissions only from 

existing EGUs within the same subcategory, such EGUs in an 

emissions averaging plan may use an alternate compliance 

approach consisting of a 90-boiler operating day rolling average 

emission limit of 1.0 lb/TBtu or 1.1E-2 lb/GWh.

In the memo entitled “The Impact of Emission Averaging Time 

on the Stringency of an Emission Standard” in the docket, we 

have illustrated why a longer-term average results in a lower 

limit. In essence, longer-term averages allow particularly high 

(or low) measurements to be averaged with many more measurements 

closer to the mean. This results in the highest averages from a 

longer-term averaging period (e.g., 90 days) being lower than 

the highest averages in a shorter term averaging period (e.g., 

30 days).

We have illustrated this concept by taking Hg CEMS data and 

calculating rolling 30-day averages and rolling 90-day averages. 

The 30-day averages have greater variability and, thus, higher 

peaks and valleys. The 90-day average has less variability; 

therefore, the same unit is able to meet a tighter 90-day limit.

The EPA is providing this alternate 90-day rolling average 

compliance approach for Hg only. A 90-day rolling average is 
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appropriate for Hg, and only for Hg, because the health and 

environmental impacts associated with Hg are related to 

environmental loading rather than shorter term inhalation or 

other acute exposure, as is the case with HCl and PM. We believe 

that this alternative compliance approach will provide at least 

the same level of environmental protection while allowing 

companies greater flexibility to use emissions averaging. For 

example, such an approach would allow for the averaging of an 

infrequently operated unit that is operating slightly above the 

standard with a more frequently operated unit that is operating 

below the standard in the instances when the more frequently 

operated unit is in a multi-day or multi-week maintenance 

outage.

The EPA has concluded that it is permissible to establish 

within a NESHAP a unified compliance regimen that permits 

averaging within the same facility across individual existing

EGUs subject to the same standards under certain conditions. As 

mentioned earlier, individual EGUs within an emissions averaging 

group would be allowed to have emissions greater than, less 

than, or equivalent with the emissions limit for their 

subcategory, provided that the average emissions comprised from 

individual EGU emissions do not exceed the emissions limit for 

their subcategory. Averaging across affected units is permitted 
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only if it can be demonstrated that the total quantity of any 

particular HAP that may be emitted by that portion of a 

contiguous major source that is subject to the same standards in 

the NESHAP will not be greater under the averaging mechanism 

than it could be if each individual affected EGU in the 

subcategory complied separately with the applicable standard. 

Under this test, the practical outcome of averaging is 

equivalent to compliance with the MACT floor limits by each 

discrete EGU, and the statutory requirement that the MACT 

standard reflect the maximum achievable emissions reductions is, 

therefore, fully effectuated.

As noted in the proposal preamble, in past rulemakings, the 

EPA has generally imposed certain limits on the scope and nature 

of emissions averaging programs. These limits include: 1) No 

averaging between different types of pollutants; 2) No averaging 

between sources that are not part of the same affected source; 

3) No averaging between individual sources within a single major 

source if the individual sources are not subject to the same 

NESHAP; and 4) No averaging between existing sources and new 

sources.

The final rule fully satisfies each of these criteria. 

First, emissions averaging would only be permitted between 

individual existing sources at a single stationary source (i.e., 
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the facility), and would only be permitted between individual 

sources in the same subcategory in the final EGU NESHAP. 

Further, emissions averaging would not be permitted between two 

or more different affected sources. Finally, new affected 

sources could not use emissions averaging. Accordingly, we have 

concluded that the averaging of emissions across affected units 

in the same existing source subcategory is consistent with the 

CAA. In addition, the final rule requires each facility that 

intends to utilize emissions averaging to develop an emissions 

averaging plan, which provides additional assurance that the 

necessary criteria will be followed. In this emissions averaging 

plan, the facility must include the identification of: 1) all 

units in the averaging group; 2) the control technology 

installed; 3) the process parameter that will be monitored; 4) 

the specific control technology or pollution prevention measure 

to be used; 5) the test plan for the measurement of the HAP 

being averaged; and 6) the operating parameters to be monitored 

for each control device. A state, local, or tribal regulatory 

agency that is delegated authority for this rule could require 

the emissions averaging plan to be submitted or even approved 

before emissions averaging could be used. Upon receipt, the 

regulatory authority would not be able to approve an emissions 

averaging plan differing from the eligibility criteria contained 
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in the rule.

The final rule excludes new affected sources from the 

emissions averaging provision. The EPA does not believe the 

statute authorizes emissions averaging for new affected sources. 

One reason we allow emissions averaging is to give existing 

sources flexibility to achieve compliance at diverse points with 

varying degrees of add-on control already in place in the most 

cost-effective and technically reasonable fashion.

With the monitoring and compliance provisions that are 

being finalized, there is additional assurance that the 

environmental benefit will be realized. Further, the emissions 

averaging provision would not apply to individual EGUs if the 

EGU shares a common stack with units in other subcategories, 

because in that circumstance it is not possible to distinguish 

the emissions from each individual unit.317

The rule allows EGUs that rely on CEMS for compliance 

demonstrations to be able to participate in emissions averaging 

and the emissions limits are not subject to a discount. The EPA 

believes that the data certainty provided by units that use CEMS 

would be ideal for emissions averaging and the flexibility and 

cost-effectiveness it offers. Given the homogeneity of fuels 

 

317 The EPA has reviewed monitoring data submitted to the Agency 

under the Title IV Acid Rain Program. Based on that review, the 

EPA is unaware of any coal- and oil-fired units that share a 

common stack.
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within the rules subcategories, along with other emissions 

averaging criteria, the Agency believes use of a discount factor 

to be unwarranted for this rule. 

The emissions averaging provisions in this final rule are 

based in part on the emissions averaging provisions in the 

Hazardous Organic NESHAP (HON). The legal basis and rationale 

for the HON emissions averaging provisions were provided in the 

preamble to the final HON.318 We do not believe that we have the 

authority to provide for emissions averaging among EGUs in 

different subcategories or among EGUs not physically located at 

the same affected facility.

I. Notification, Recordkeeping, and Reporting

Compared to the proposed rule, the reduced continuous 

compliance requirements in the final rule – primarily reduced 

testing frequencies and removal of fuel analyses and control 

device or fuel operating parameter monitoring – considerably 

reduces the overall burden associated with recordkeeping and 

reporting. Based on evaluation of the comments received, we have 

established a provision in the final rule for submission of most 

CEMS data (including monitoring plan, emissions data, and QA 

data) through ECMPS, so that the affected industry uses a common 

reporting tool for submitting CEMS data. 

For data other than most CEMS data, the final rule requires 

 

318 Hazardous Organic NESHAP (59 FR 19,425; April 22, 1994).
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electronic reporting of certain data, including performance test 

reports, PM CPMS data, PM CEMS data, and, if approved as part of 

an alternative monitoring request, HAP metals CEMS data. Other 

reports, such as notifications, must be submitted in hard copy 

format or in accordance with the procedures established by state 

and local agencies that receive delegation for implementing this 

rule. In the proposed rule, we took comment on these approaches 

and stated our anticipation of adopting these approaches. In the 

final rule, we have extended the ECMPS reporting to most CEMS 

data to promote harmonization for CEMS data from the industry, 

while leaving reporting of non-CEMS data in a separate reporting 

system.

J. Technical/Editorial Corrections

In this final action, we are making a number of technical 

corrections and clarifications to 40 CFR Part 63, subpart UUUUU. 

These changes clarify procedures for implementing the emission 

limitations for affected sources. We are also clarifying several 

definitions to help affected sources determine applicability of 

this rule. We have modified some proposed regulatory language 

based on public comments. In addition, in response to comments 

received (including the May 2010 notice from the Utility Air 

Regulatory Group (UARG) of calculation errors in the proposed Hg 

MACT floor limits), we have checked all calculations and made 
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corrections where necessary.

In several places throughout the subpart, including the 

associated tables, we have corrected the cross-references to 

other sections and paragraphs of the subpart.

VII. Public Comments and Responses to the Proposed NESHAP

A. MACT Floor Analysis

1. New Data/Technical Corrections to Old Data

Comment: Many commenters identified errors in the emissions 

database compiled through information provided by industry in 

response to the 2010 information collection request (ICR) that 

supported development of this rule. Commenters submitted 

corrections to the EPA during the public comment period.

Response: The EPA has incorporated technical corrections and new 

data submitted prior to the end of the comment period. The 

corrections and new data are described in detail in a memorandum 

in the docket. The EPA re-ranked the sources in the MACT floor 

pools to the extent necessary based on the new or corrected 

data, and we recalculated the MACT floors as necessary based on 

the re-ranking of sources. The revised MACT floors were 

established using the same methodology set forth in the proposed 

rule.

2. Pollutant-by-pollutant approach

Comment: Many commenters raised concerns about the way the EPA
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determined the MACT floors using a pollutant-by-pollutant 

approach. Commenters contended that such a methodology produced 

limits that are not achievable in combination, and as such, the 

limits do not comport with the intent of the statute or the 

recent court decision (NRDC v. EPA, 2007). Commenters further 

added that the CAA directs the EPA to set standards based on the 

overall performance of “sources” and CAA sections 112(d)(1), 

(2), and (3) specify that emissions standards be established on 

the “in practice” performance of a “source” in the category or 

subcategory. Commenters stated that if Congress had intended for 

the EPA to establish MACT floor levels considering the 

achievable emission limits of individual HAP, it could have 

worded CAA section 112(d)(3) to refer to the best-performing 

sources “for each pollutant.” Many commenters added that the 

EPA’s discretion in setting standards is limited to 

distinguishing among classes, types, and sizes of sources.

Commenters contend that although Congress limited the EPA’s 

authority to parse units and sources with similar design and 

types, it does not allow the EPA to “distinguish” units and 

sources by individual pollutant as proposed in this rule (Sierra 

Club v. EPA, 551 F.3d 1019, 1028 (D.C. Cir. 2008)). By 

calculating each MACT floor independently of the other 

pollutants, commenters contend that the combination of HAP 
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limits results in a set of standards that only a hypothetical 

“best performing” unit could achieve.

Response: We disagree with the commenters who believe MACT 

floors cannot be set on a pollutant-by pollutant basis. Contrary 

to the commenters’ suggestion, CAA section 112(d)(3) does not 

mandate a total facility approach. A reasonable interpretation 

of CAA section 112(d)(3) is that MACT floors may be established 

on a HAP-by-HAP basis, so that there can be different pools of 

best performers for each HAP. Indeed, as illustrated below, the 

total facility approach not only is not compelled by the 

statutory language but can lead to results so arbitrary that the 

approach may simply not be legally permissible. 

Clean Air Act section 112(d)(3) is not explicit as to 

whether the MACT floor is to be based on the performance of an 

entire source or on the performance achieved in controlling 

particular HAP. Congress specified in CAA section 112(d)(3) the 

minimum level of emission reduction that could satisfy the 

requirement to adopt MACT. For new sources, this floor level is 

to be “the emission control that is achieved in practice by the 

best controlled similar source.” For existing sources, the floor 

level is to be “the average emission limitation achieved by the 

best performing 12 percent of the existing sources” for 

categories and subcategories with 30 or more sources, or “the 
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average emission limitation achieved by the best performing 5 

sources” for categories and subcategories with fewer than 30 

sources. Commenters point to the statute’s reference to the best 

performing “sources,” and claim that Congress would have 

specifically referred to the best performing sources “for each 

pollutant” if it intended for the EPA to establish MACT floors 

separately for each HAP.

The EPA disagrees. The language of the Act does not address 

whether floor levels can be established HAP-by-HAP or by any 

other means. The reference to “sources” does not lead to the 

assumption the commenters make that the best performing sources 

can only be the best-performing sources for the entire suite of 

regulated HAP. Instead, the language can be reasonably 

interpreted as referring to the source as a whole or to 

performance as to a particular HAP. Similarly, the reference in 

the new source MACT floor provision to “emission control 

achieved by the best controlled similar source” can mean 

emission control as to a particular HAP or emission control 

achieved by a source as a whole.

Commenters also stressed that CAA section 112(d) requires 

that floors be based on actual performance from real facilities. 

The EPA agrees that this language refers to sources’ actual 

operation, but again the language says nothing about whether it 
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is referring to performance as to individual HAP or to single 

facility’s performance for all HAP. Industry commenters also 

said that Congress could have mandated a HAP-by-HAP result by 

using the phrase “for each HAP” at appropriate points in CAA

section 112(d). The fact that Congress did not do so does not 

compel any inference that Congress was sub-silentio mandating a 

different result when it left the provision ambiguous on this 

issue. The argument that MACT floors set HAP-by-HAP are based on 

the performance of a hypothetical facility, so that the 

limitations are not based on those achieved in practice, just 

reiterates the question of whether CAA section 112(d)(3) refers 

to whole facilities or individual HAP. All of the limitations in 

the floors in this rule reflect sources’ actual performance and 

were achieved in practice. As to commenters’ claims that 

standards set in this manner cannot be met by any actual 

sources, we have determined that there are approximately 69

existing coal-fired EGUs that meet all of the final existing 

source MACT emission limits (out of 252 EGUs that reported data 

for Hg, PM, and HCl in the 2010 ICR) and at least one EGU that 

meets all of the final new source MACT emission limits.

Commenters also point to the EPA’s subcategorization 

authority, and claim that because Congress authorized the EPA to 

distinguish among classes, types, and sizes of units, the EPA
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cannot distinguish units by individual pollutant, as they allege 

the EPA did in the proposed rule. However, that statutory 

language addresses the EPA’s authority to subcategorize sources 

within a source category prior to setting standards, which the 

EPA has done for certain EGUs. The EPA is not distinguishing 

within each subcategory based on HAP emitted. Rather, it is 

establishing emissions standards based on the emissions limits 

achieved by units in each subcategory. Therefore, the EPA’s 

subcategorization authority is irrelevant to the question of how 

the EPA establishes MACT floor standards once it has made the 

decision to distinguish among sources and create subcategories.

The EPA’s long-standing interpretation of the Act is that 

the existing and new source MACT floors are to be established on 

a HAP-by-HAP basis. One reason for this interpretation is that a 

whole plant approach could yield least common denominator floors 

– that is floors reflecting limited or no control, rather than 

performance which is the average of what best performers have 

achieved. See 61 FR 173687 (April 19, 1996); 62 FR 48363-64 

(September 15, 1997) (same approach adopted under the very 

similar language of CAA section 129(a)(2)). Such an approach 

would allow the performance of sources that are outside of the 

best-performing 12 percent for certain pollutants to be included 

in the floor calculations for those same pollutants, and it is 
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even conceivable that the worst performing source for a 

pollutant could be considered a best performer overall, a result 

Congress could not have intended. Inclusion of units that are 

outside of the best performing 12 percent for particular 

pollutants would lead to emission limits that do not meet the 

requirements of the statute.

For example, if the best performing 12 percent of 

facilities for HAP metals were also the worst performing units 

for acid gas HAP and the best performers for acid gas HAP were 

the worst performers for HAP metals, the floor for acid gases or 

metals would end up not reflecting best performance. In such a 

situation, the EPA would have to make a value judgment as to 

which pollutant reductions were most critical to decide which 

sources are best controlled.319 Such value judgments are 

antithetical to the direction of the statute at the MACT floorsetting stage.

Commenters suggested that a multi-pollutant approach could 

be implemented by weighting pollutants according to relative 

toxicity and calculating weighted emissions totals to use as a 

basis for identifying and ranking best performers. This 

 

319 See Petitioners Brief in Medical Waste Institute et al. v. 

EPA, No. 09-1297 (D.C. Cir.) pointing out, in this context, that 

“the best performers for some pollutants are the worst 

performers for others” (p. 34) and “[s]ome of the best 

performers for certain pollutants are among the worst performers 

for others.”
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suggested approach would require the EPA to essentially 

prioritize the regulated HAP based on relative risk to human 

health of each pollutant, where risk is a criterion that has no 

place in the establishment of MACT floors, which are required by 

statute to be based on technology.

The central purpose of the amended air toxics provisions 

was to apply strict technology-based emission controls on HAP. 

See, e.g., H. Rep. No. 952, 101st Cong. 2d sess. 338. An 

interpretation that the floor level of control must be limited 

by the performance of devices that only control some of these 

pollutants effectively guts the standards by including worse 

performers in the averaging process, whereas the EPA’s 

interpretation promotes the evident Congressional objective of 

having the floor reflect the average performance of best 

performing sources. Because Congress has not spoken to the 

precise question at issue, and the Agency’s interpretation 

effectuates statutory goals and policies in a reasonable manner, 

its interpretation must be upheld. See Chevron v. NRDC, 467 U.S. 

837 (1984).320

 

320 Because industry commenters argued that the statute can only 

be read to allow floors to be determined on a single source 

basis, commenters offered no view of why their reading could be 

viewed as reasonable in light of the statute’s goals and 

objectives. It is not evident how any statutory goal is promoted 

by an interpretation that allows floors to be determined in a 

manner likely to result in floors reflecting emissions from 

worst or mediocre performers. 
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The EPA notes, however, that if optimized performance for 

different HAP is not technologically possible due to mutually 

inconsistent control technologies (for example, if metals 

performance decreased as organics reduction is optimized), then 

this would have to be taken into account by the EPA in 

establishing a floor (or floors). The Senate Report indicates 

that if certain types of otherwise needed controls are mutually 

exclusive, the EPA is to optimize the part of the standard 

providing the most environmental protection. S. Rep. No. 228, 

101st Cong. 1st sess. 168 (although, as noted, the bill 

accompanying this Report contained no floor provisions). It 

should be emphasized, however, that the D.C. Circuit has stated 

that “the fact that no plant has been shown to be able to meet 

all of the limitations does not demonstrate that all the 

limitations are not achievable.” Chemical Manufacturers 

Association v. EPA, 885 F. 2d at 264 (upholding technology-based 

standards based on best performance for each pollutant by 

different plants, where at least one plant met each of the 

limitations but no single plant met all of them).

All available data for EGUs indicate that there is no 

technical problem achieving the floor levels contained in this 

final rule for each HAP simultaneously, using the MACT floor 

technology. Data demonstrating a technical conflict in meeting 
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all of the limits have not been provided, and, as stated above, 

based on the available data, there are approximately 64 EGUs 

that meet all of the final existing source emission limits and 

at least one EGU that meets all of the final new source emission 

limits.

3. Minimum Number of EGUs to Set Floors

Comment: Many commenters indicated that CAA section 112 requires 

that data from a minimum of 5 units are required to set MACT 

floors for existing sources. Commenters noted that the EPA’s use 

of less than 5 units for subcategories with greater than 30 

units is a legalistic reading of CAA section 112 that could 

result in such absurd results as using 5 units to set MACT 

floors for a subcategory with 29 units and data for only 10 

units, but using a single unit to set MACT floors for a 

subcategory with 31 units and data for only 10 units.

Response: The EPA does not agree that CAA section 112(d)(3) 

mandates a minimum of 5 sources in all instances, 

notwithstanding the incongruity of having less data to establish 

floors for larger source categories than is mandated for smaller 

ones. The literal language of the provision appears to compel 

this result. CAA section 112(d)(3) states that for categories 

and subcategories with at least 30 sources, the MACT floor for 

existing sources shall be no less stringent than the average 
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emission limitation achieved by the best-performing 12 percent 

of the sources for which the Administrator has emissions 

information. The plain language of this provision requires the 

use of fewer data points for large source categories than for 

small source categories where the Administrator only has 

emissions information on a small number of units for categories 

and subcategories with 30 or more sources. Furthermore, 

commenters contend that Congress could not have intended the 

floors for a subcategory with 29 sources to be based on 5 

sources and a subcategory with 31 sources to be based on less 

than that number; but we maintain this contention is without 

merit because 12 percent of 31 is 3.72 (rounded to 4) so the EPA

would not base standards for a subcategory with 31 sources on 5 

sources even if we had data on all 31 sources in the 

subcategory. For these reasons, we decline to adopt commenters’

position and continue to adhere to the clear statutory 

directive.

4. Treatment of Detection Levels

Comment: Commenters stated that when setting the MACT floors, 

non-detect values are present in many of the datasets from best 

performing units. Commenters provided input on how these nondetect values should be treated in the MACT floor analysis. Some 

commenters agreed that it is appropriate to keep the detection 
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levels as reported, while certain commenters suggested that the 

detection levels should be replaced using a value of half the 

method detection limit (MDL). Many other commenters stated that 

data that are below the detection limit should not be used in 

setting the floors, and these data should be replaced with a

higher value including either the MDL, limit of quantitation 

(LOQ), practical quantitation limit (PQL), or reporting limit 

(RL) for the purposes of the MACT floor calculations. Other 

commenters stated all non-detect values should be excluded from 

the floor analysis, or all values should be treated as zero.

Some commenters stated it is necessary to keep the data as 

reported because changing values would lead to an upward bias. 

Additional commenters agreed with this basic premise, but 

suggested that replacing non-detect data with a value of half 

the MDL is appropriate while still minimizing the bias. They 

noted that treating measurements below the MDL as occurring at 

the MDL is statistically incorrect and violates the statute’s 

“shall not be less stringent than” requirement for MACT floors. 

One commenter also provided a reference for a statistical method 

based on a log-normal distribution of the data which estimated 

the “maximum likelihood” of data values; this result is slightly 

higher than half the MDL.

Some commenters stated that it is necessary to substitute 
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the MDL value when performing the MACT floor calculations. With 

MDL defined as the lowest concentration that can be 

distinguished from the blank at a defined level of statistical 

significance, this is an appropriate value. If MDL values are 

not reported, one commenter suggested an approach for estimating 

an MDL equivalent value, but recognized that the background 

laboratory and test report files may not be available to the EPA

in order to derive these estimates.

Most commenters representing industry and industry trade 

groups argued that either LOQ or PQL values should replace nondetects. The LOQ is defined as the smallest concentration of the 

analyte which can be measured. These commenters contended that 

the LOQ leads to a quantifiable amount of the substance with an 

acceptable level of uncertainty. A few commenters provided 

calculations showing some of the proposed MACT floors were below 

the LOQ. Additionally, some of these commenters stated that 

using LOQ or PQL values also incorporates additional sources of 

random and inherent sampling error throughout the testing 

process, which is necessary. These errors occur during sample 

collection, sample recovery, and sample analysis; MDL values 

only account for method specific (e.g., instrument) errors. 

These commenters contended that the three times the MDL approach 

discussed in the proposal accounts for some measurement errors 
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but does not account for these unavoidable sampling errors. The 

commenters also noted that an LOQ is calculated as 3.18 times 

the MDL, and PQL is calculated as 5 to 10 times the MDL. Many of 

the commenters in support of using either an LOQ or PQL value 

ultimately believed a work practice is more appropriate where a 

MACT floor limit is below either of these two values. They cited 

CAA section 112(h)(1) which allows work practices under CAA 

section 112(h)(2) if “the application of measurement methodology 

to a particular class of sources is not practicable due to 

technological and economic limitations”. These commenters stated 

that the inability of sources to accurately measure a pollutant 

at the level of the MACT floor qualifies as such a technological 

limitation that warrants a work practice standard.

Commenters stated that where the proposed MACT floor is 

below the LOQ or PQL then that source category has a 

technological measurement limitation. A few commenters suggested 

RL values should be used when developing the floor limits. They 

stated that the RL is the lowest level at which the entire 

analytical system gives reliable signals and includes an 

acceptable calibration point. They added that use of an 

acceptable calibration point is critical in showing that numbers 

are real versus multiplying the MDL by various factors. 

Several commenters stated that all non-detect values should 
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be excluded from MACT floor calculations. They believed that 

excluding all non-detect values would eliminate any potential 

errors or accuracy issues related to testing for compliance. Due 

to inconsistencies of the MDL value reported for non-detect 

data, one commenter suggested treating all such values as zero. 

This would provide a consistent approach for setting the floor 

as well as determining compliance.

Several commenters provided input on the EPA’s proposed 

method of three times the MDL as an option for setting limits. A 

few commenters in support noted that this approach provided a 

reasonable method to account for data variability as it took 

into account more than just analytical instrument precision. 

Many other commenters argued that this method results in limits 

which are too low, namely that it is still lower than the LOQ 

value which they are in favor of as a substitute for any 

reported non-detect data. Other commenters disagreed with this 

method and claimed that it would lead to results which introduce 

a high bias in the floor setting process. A few contended that 

multiplying by 3 would introduce a 300 percent error into the 

floor, resulting in a floor that is less stringent than required 

by the Act. Others suggested that the MDL values are antiquated 

and already too high and thus it is not appropriate to multiply 

them by three. Also, a few commenters suggested multiplying the 
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MDL by three would not reflect the actual lower emissions 

achieved by any source and as such is unlawful under CAA section 

112(d).

Response: We agree with many of comments related to treatment of 

data reported as detection limit values in the development of 

MACT floors and emissions limits. As we noted at proposal, the 

statistical probability procedures applied in calculating the 

floor or an emissions limit inherently and reasonably account 

for emissions data variability including measurement imprecision 

when the database represents multiple tests from multiple 

emissions units for which all of the data are measured 

significantly above the method detection level. That is less 

true when the database includes emissions occurring below method 

detection capabilities regardless of how those data are 

reported. 

The EPA’s guidance to respondents for reporting pollutant 

emissions used to support the data collection specified the 

criteria for determining test-specific method detection levels. 

Those criteria ensure that there is only about a 1 percent 

probability of an error in deciding that the pollutant measured 

at the method detection level is present when in fact it was 

absent. (Reference: ReMAP: PHASE 1, Precision of Manual Stack 

Emission Measurements; American Society of Mechanical Engineers, 
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Research Committee on Industrial and Municipal Waste, February 

2001.) Such a probability is also called a false positive or the 

alpha, Type I, error. This means specifically that for a 

normally distributed set of measurement data, 99 out of 100 

single measurements will fall within ±2.54 x standard deviation 

of the true concentration. The anticipated range for the average 

of repeated measurements comes progressively closer to the true 

concentration. More precisely, the anticipated range varies 

inversely with the square root of the number of measurements. 

Thus, for a known standard deviation (SD) of anticipated single 

measurements, the anticipated range for 99 out of 100 future 

triplicate measurements will fall within ± 2.54 SD/√3 of the 

true concentration. This relationship translates to an expected 

measurement imprecision for an emissions value occurring at or 

near the method detection level of about 40 to 50 percent.

By assuming a similar distribution of measurements across a 

range of values and increasing the mean value to a 

representative higher value (e.g., 3 times minimum detection 

level or 3xMDL), we can estimate measurement imprecision at 

other levels. For an assumed 3xMDL, the estimated measurement 

imprecision for a three test run average value would be on the 

order 10 to 20 percent. This is about the same measurement 

imprecision as found for Methods 23 and 29 indicated in the ASME
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ReMAP study for the sample volumes prescribed in the final rule 

(e.g., 4 to 6 dscm) for multiple tests.

Analytical laboratories often report a value above the 

method detection limit that represents the laboratory’s 

perceived confidence in the quality of the value. This 

independently adjusted value is expressed differently by various 

laboratories and is called LOQ, PQL, or RL. In many cases, the 

LOQ, PQL, or RL is simply a multiplication of the method 

detection limit. Commonly used multipliers range from 3 to 10. 

Because these values reflect individual laboratories’ perceived 

confidence, and, therefore, could be viewed as arbitrary, we 

decline to adopt the LOQ, PQL, or RL because such approaches in 

our view would inappropriately inflate the MACT floor standards. 

Our alternative to those inconsistent approaches is discussed 

below.

Consistent with findings expressed in reports of emissions 

measurement imprecision and the practices of analytical 

laboratories, we believe that using a measurement value of 3 

times a representative method detection limit established in a 

manner that assures 99 percent confidence of a measurement above 

zero will produce a representative method reporting limit 

suitable for establishing regulatory floor values.

On the other hand, we also agree with commenters that an 
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emissions limit set from a small subset of data or data from a 

single source may be significantly different than the actual 

method detection levels achieved by the best performing units in 

practice. This fact, combined with the low levels of emissions 

measured from many of the best performing units, led the EPA

since proposal to review and revise the procedure intended to 

account for the contribution of measurement imprecision to data 

variability in establishing effective emissions limits. In 

response to the comments about the quality of measurements at 

very low emissions limits especially for new sources, we revised 

the procedure for identifying a representative method detection 

level (RDL). 

The revised procedure for determining an RDL starts with 

identifying all of the available reported pollutant-specific 

method detection levels for the best performing units regardless 

of any subcategory (e.g., existing or new, fuel type, etc.). 

From that combined pool of data, we calculate the arithmetic 

mean value. By limiting the data set to those tests used to 

establish the floor or emissions limit (i.e., best performers), 

which in this case is a larger data set than normally available 

for establishing NESHAP, we believe that the result is 

representative of the best performing testing companies and 

laboratories using the most sensitive analytical procedures. We 
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believe that the outcome should minimize the effect of a test(s) 

with an inordinately high method detection level (e.g., the 

sample volume was too small, the laboratory technique was 

insufficiently sensitive, or the procedure for determining the 

minimum value for reporting was other than the detection level). 

We then call the resulting mean of the method detection levels 

the representative detection level (RDL) because it is

characteristic of accepted source emissions measurement 

performance. 

The second step in the process is to calculate 3xRDL to 

compare with the calculated floor or emissions limit. This step 

is similar to what we have used for other NESHAP including the 

Portland Cement rule. As outlined above, we use the 

multiplication factor of 3 to reduce the imprecision of the 

analytical method until the imprecision in the field sampling 

reflects the relative method precision as estimated by the ASME 

ReMAP study. That study indicates that such relative imprecision 

remains a constant 10 to 20 percent over the range of the 

method. For assessing the calculated floor results relative to 

measurement method capabilities, if 3xRDL were less than the 

calculated floor or emissions limit (e.g., calculated from the 

upper predictive limit, UPL), we would conclude that measurement 

variability was adequately addressed with the initial floor 
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calculation. The calculated floor or emissions limit would need 

no adjustment. If, on the other hand, the value equal to 3xRDL 

were greater than the UPL, we would conclude that the calculated 

floor or emissions limit did not account entirely for 

measurement variability. Where such was the case, we substituted 

the value equal to 3xRDL for the calculated floor or emissions 

limit (UPL) which results in a concentration where the method 

would produce measurement accuracy on the order of 10 to 20 

percent similar to other EPA test methods and the results found 

in the ASME ReMAP study.

We determined the RDL for each pollutant using data from 

tests of all the best performers for all of the final regulatory 

subcategories (i.e., pooled test data). We applied the same 

pollutant-specific RDL and emissions limit assessment and 

adjustment procedures to all subcategories for which we 

established emissions limits. We believe that adjusting 

emissions limits in this manner, which ensures that measurement 

variability is adequately addressed relative to compliance 

determinations, is a better procedure than the one applied at 

proposal, which was based on more limited data. We also believe 

that currently available emissions testing procedures and 

technologies provide the measurement certainty sufficient for 

sources to demonstrate compliance at the levels of the revised 
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emissions limits.

5. Basis for New source MACT

Comment: Several commenters stated that the proposed limits set 

for new EGUs do not represent the best performing EGU. The 

commenters state that the EPA has chosen the strictest limit 

irrespective of the EGU and that limits for new EGUs should be 

achievable. According to the commenters, no existing EGU is 

currently meeting the proposed limits, which will result in a 

moratorium on the construction of new coal-fired EGUs. Further, 

commenters state that another result of the EPA’s flawed 

approach is that the proposed standards for new EGUs are so low 

that adequate test methodologies to demonstrate compliance do 

not exist. Without accurate testing methodologies, commenters 

assert that contractors will not guarantee that potential 

emission control technologies will meet the proposed standards. 

Without accurate test methodologies and vendor guarantees, 

commenters believe that financing of new facilities will be 

virtually impossible to secure which will, in turn, effectively 

preclude the construction of any new coal-based EGUs.

Commenters also stated that the EPA failed to address 

cumulative effects of using multiple pollution control devices 

in determining MACT levels applicable to PM levels. In proposing 

total PM as a surrogate, commenters believe that the EPA failed 
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to consider or address the antagonistic effects that adding 

multiple pollution control devices can have on an EGU’s HAP 

emissions. Commenters indicated that EGUs would not be able to 

comply with the proposed new source HCl limit without adding a 

scrubber or some type of sorbent injection to control HCl 

emissions. Adding these HCl control technologies will increase 

the total PM emissions of these units. According to commenters, 

because a fabric filter-alone configuration (the basis for the 

new source PM limit) would not meet all MACT limits, these units 

may not be the best-performing units.

Response: The EPA disagrees with the commenters’ statements that 

no existing unit is currently meeting the new source limits. The 

EPA established the new source limits based on data from 

existing EGUs and there is at least one EGU, based on the data 

available, that is meeting all three final HAP limits and at 

least eight EGUs that are meeting one or more of the new source

limits. As a result of comments received on the full body of 

data, the EPA has re-ranked the best performing EGUs and 

reviewed the new source limits based on the re-ranking where 

appropriate. Based on the revised ranking, the best performing 

source for PM has changed and that source now forms the basis 

for the new source filterable PM limit in the final rule. The 

source is a coal-fired EGU that includes the entire suite of 
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controls that would likely be required on a new coal-fired 

source constructed prospectively (i.e., it is a unit with SCR, 

dry FGD, and FF). Thus, the commenters’ concerns are no longer 

relevant as they relate to PM emissions from coal-fired EGUs.

The EPA also believes that the EGUs serving as the basis 

for the new source Hg and HCl limits in the final rule are 

representative of what a new coal-fired EGU would look like to 

meet all of the requisite regulations applicable to EGUs (e.g., 

NSPS and the CSAPR) as they also include the entire suite of 

controls that would likely be required on a new coal-fired 

source constructed prospectively. The EPA has also taken into 

account the ability of the various test methods to accurately 

measure emissions at the levels being demonstrated by the EGUs 

in the top performing 12 percent in establishing the final 

limits, and we have determined that there are aqequate test 

methods to measure the regulated HAP at the new source levels.

6. Achievability of Limits

Comment: A number of commenters state that the EPA has chosen 

the strictest limit irrespective of the unit and that limits for 

new EGUs should be achievable. According to the commenters, no 

existing unit is currently meeting the proposed new source

limits, which will result in a moratorium on the construction of 

new coal-fired units. The commenters state that this regulation 
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goes beyond protecting public health and will impact the 

country’s choice of fuel for energy production. Other commenters 

state that another result of the EPA’s flawed approach is that 

the proposed standards for new units are so low that adequate 

test methodologies to demonstrate compliance do not exist. 

Without accurate testing methodologies, commenters allege that 

contractors will not guarantee that potential emission control 

technologies will meet the proposed standards. Without accurate 

test methodologies and vendor guarantees, commenters believe 

that financing of new facilities will be virtually impossible to 

secure, and that this in turn will effectively preclude the 

construction of any new coal-based units. Commenters maintain 

that adopting standards effectively banning new coal units 

amounts to a momentous change in national energy policy without 

discussion or analysis and far exceeds the EPA’s authority.

Some commenters add that the proposed new source MACT 

standards do not represent rates that have been achieved in 

practice and are orders of magnitude lower than any of the CAA 

section 112(g) case-by-case MACT limits established for the most 

advanced units in the U.S. coal fleet by multiple state 

agencies.

Other commenters stated that the synergistic impact of 

multiple controls has not been taken into account in the 
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proposed rules. Commenters argue that circumstances exist with 

respect to the control of acid gases, which will require 

scrubbers or other SO2 controls that add particulate to the flue 

gas stream, and that added particulate must be removed by PM 

control devices along with the particulate added to the flue gas 

for EGUs that need to install ACI for Hg control. Because 

particulate devices provide a fixed percent reduction of 

particulate, commenters assert that it is mathematically certain 

that PM performance will decrease because control of both acid 

gases and Hg would add PM to the flue gas stream which would in 

turn decrease performance of the PM control on the relevant mass 

metric. As a consequence, commenters allege that there is no 

assurance that sources can meet the EPA’s “cherry-picked” floors 

for acid gases and for Hg by “optimizing” these systems to meet 

the performance of the floor units because to do so would impact 

their ability to meet the EPA’s similarly “cherry-picked” total 

PM floor standard.

The commenters state that, for existing sources as with the 

new source standard-setting approach, a pollutant-by-pollutant 

approach does not consider what the top performing 12 percent 

achieve in practice for all pollutants and does not consider the 

antagonistic effects of the concurrent use of various control 

technologies. For example, one commenter states that 47 of the 
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131 sources used to calculate the existing source total PM limit 

only had PM control but no acid gas or Hg controls that could 

emit additional PM. According to the commenter, the CAA is clear 

that standards must be based on actual sources and not the 

product of a pollutant-by-pollutant determination resulting in a 

set of composite standards that do not necessarily reflect the 

overall performance of any actual source. To address these 

issues, the commenter recommends that the EPA use an approach 

that more accurately reflects what actual best performing 

sources achieve.

Response: The EPA disagrees with the commenters’ contention that 

the pollutant-by-pollutant approach to establishing MACT floors 

is inconsistent with the CAA for the reasons set forth in the 

response to comments on the EPA’s MACT floor setting process. In 

addition, the EPA established the proposed new source limits 

based on data from existing EGUs, and there are EGUs that are 

able to meet the new source limits. To the extent the commenters 

are concerned that no existing source is simultaneously meeting 

all of the new sources limits, we note that the EPA has revised 

the new source standards based on comments and data corrections 

that industry made to data it incorrectly provided in response 

to the utility ICR. We have identified at least one source that 

is meeting all of the new source MACT limits in the final rule.
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We disagree with commenters that suggest the proposed new 

source standards are invalid because they are more stringent 

than CAA section 112(g) case-by-case MACT limits established by 

state agencies. As commenters note, states, not the EPA, 

established the CAA section 112(g) standards, and they did so 

based on the information available to them. The EPA likewise 

must establish CAA section 112(d) standards based on the 

available data. We have considered the available data and 

information, including the 2010 ICR data, and complied with the 

requirements of CAA section 112(d) in establishing the standards 

in this final rule. That the final standards are more stringent 

than CAA section 112(g) standards issued by certain state 

agencies has no bearing on the legitimacy of the standards at 

issue here.

The EPA agrees with commenters that the SO2 and some Hg 

controls may add to the PM loading and that it is reasonable to 

establish the new source standard based on an EGU that has a 

suite of controls that will be required of any new source. For 

example, new coal-fired EGUs will be required to comply with the 

utility NSPS and may have to comply with the CSAPR and other 

requirements (e.g., SIP or state-only requirements). Commenters 

are also correct that the proposed new source PM surrogate 

standard was based on a source that is not like a coal-fired EGU 
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that would be constructed today (i.e., an EGU with only PM 

control and no SO2 controls).

The final standard is not based on the source used to 

establish the proposed limit. As stated above, industry

commenters provided data corrections and new data and the EPA

considered that new and revised data in establishing the final 

standards. We re-ranked all the coal-fired EGUs based on the new 

data. The new ranking of coal-fired EGUs resulted in a change of 

the source we used to establish the new source PM surrogate 

standard for non-mercury metal HAP. The basis for the new source

limit in the final rule is a unit that has a full suite of 

controls similar to what would be required for any new coalfired EGUs (i.e., it is a unit with SCR, dry FGD, and FF). The 

EPA has identified at least one EGU meeting all of the final new 

source limits; thus, the EPA does not believe that it is 

finalizing standards that “ban” new coal-fired generation as 

indicated by the commenter.

The EPA also disagrees that the final new source standards 

are so stringent that there are not adequate test methods 

available to determine compliance with the standards. The EPA 

has taken into account the ability of the various test methods 

to accurately measure emissions at the levels being demonstrated 

by the best performing EGUs in establishing the final limits.
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This has been done through use of the 3XRDL (discussed elsewhere 

in this preamble and the Response to Comments document) and 

through adjustments to the sampling time requirements for 

certain of the HAP.

7. Comments on Technical Approaches

Comment: Commenters disagreed with the EPA’s use of data from 

multiple units exhausting through a common stack and argued that 

the EPA unreasonably treated data from multiple units exhausting 

through a single stack as multiple data points in establishing 

the MACT floors. The commenters believe it is improper to count 

a single data point from a multiple-unit common stack as 

multiple data points. The commenters state that where two units 

exhaust through a common stack, the performance is not that of 

two sources, but only one. The commenters indicate that 

emissions performance that is actually achieved reflects 

combined operation, which cannot rationally be split into two 

parts (data points) because this emissions performance was not 

achieved by two separate sources. Commenters assert that 

although it may be acceptable for the EPA to surmise that the 

combined performance of multiple EGUs and pollution control 

devices represents an emissions control strategy that could be a 

best performer, thereby entitling the Agency to use the data at 

all, the fact is there is only one performer not two. Commenters 
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contend that apart from being inconsistent with applicable MACT 

case law, counting combined stack emissions as two or more data 

points is unreasonable because it dampens variability and overrepresents the emissions data by creating multiple “performers”

or sources when there is in fact only one. Commenters note that 

in the major-source Industrial Boiler NESHAP, the EPA argued its 

approach of creating two data points from a single combined 

stack data point is reasonable because it cannot separate the 

comingled fraction of the emissions from the different emission 

points. Commenters state that this is irrelevant, believing that 

there is no basis to separate these emissions because the MACT 

floor is based on best performing sources and there is only a 

single source. 

According to commenters, the EPA cannot determine what 

amount of the overall performance of a combined stack data point 

is the specific result of the combination. Commenters assert 

that the EPA also argues that applying the emissions equally to 

multiple units exhausting through a single stack “accurately 

represents the emissions of those units on average.” Commenters 

believe that is simply not correct and there is no plausible 

factual basis for that statement, believing that there is no 

unit that “achieved” those emissions. Rather, the data represent 

the combined weighted average of two units, without knowing how 
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either unit actually performed. One commenter also stated that 

in several instances when a facility operated tandem or multiple 

EGUs but only submitted a single stack measurement, the EPA used 

the single stack measurement to represent Hg emissions from the 

facility’s other stacks.

Response: The EPA disagrees with commenters. As in the majorsource Industrial Boiler NESHAP, the EPA continues to believe 

that the emissions from the common stack represent the average 

emissions of the EGUs exhausting to the common stack and are 

representative of both EGUs. Commenters have provided no data to 

support the contention that this assumption is false. In 

addition, commenters contention that distinct EGUs (i.e., 

boilers) are one source if they emit out of a common stack is 

not consistent with the CAA section 112(a)(8) definition, which 

clearly applies to the individual boiler units with a capacity 

of more than 25 MW. It would not be reasonable in light of that 

definition to consider the emissions from two boilers to a 

common stack as the emissions of one EGU. The EPA only used data 

from combined stacks where both EGUs were operating or where the 

owner/operator certified that no air leakage could occur. The 

EPA expects that companies will comply with the final rule by 

conducting testing at the common stack as that is usually where 

the sampling locations are (rather than in the intermediate 
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ductwork) and will report the results as being for each EGU.

The EPA has reviewed the data based on comments received 

and does not believe that there are any inconsistencies in the 

data set used for the final rule. In the MACT floor analysis, 

the EPA only used data from stacks that were tested or for which 

test data were provided. These stack measurements were not used 

to represent emissions from other, non-tested, stacks in the 

MACT analysis.

8. Alternative Units for Emission Limits

Comment: Several commenters submitted a variety of alternatives 

to the input- or output-based MACT floor limits as means of 

establishing the MACT floors. Some commenters suggested emission 

reductions or removal efficiencies. These commenters suggest 

that a percent reduction MACT metric be considered as an 

alternative, and not a substitute, to some of the proposed MACT 

numerical limits, particularly those that appear too problematic 

to meet in reality. A necessary data format and protocol could 

be developed for some HAP, such as Hg, that would allow an 

appropriate percent reduction alternative to be developed. 

Commenters believe that the Brick MACT decision stands for the 

proposition that a MACT level cannot be based on a specific 

technology; commenters are advocating that a percent reduction 

format would specify the level or reduction but would not 
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dictate any specific control or methodology.

Comments were also received that some state programs 

contain Hg emission limits that are more stringent than the 

EPA’s proposed emission limits. The programs of Connecticut, 

Massachusetts, New Hampshire, New Jersey, and New York were 

noted. Commenters provided information on these state’s Hg 

emission limits, which often are in the form of either a lb/TBtu 

format or a percent reduction. Commenters noted that EGUs in 

these states were in compliance with the state regulations and, 

therefore, the EPA’s emission limits should be more stringent.

Response: The EPA disagrees with the commenters’ suggestion that 

a percent reduction standard should be included in the final 

rule. The EPA notes that the inability to account for Hg removed 

from the coal prior to combustion was not the only reason 

provided for not using a percent reduction format. As noted in 

the proposal preamble (76 FR 25040), we did consider using a 

percent reduction format for Hg. We determined not to propose a 

percent reduction standard for several reasons. The percent 

reduction format for Hg and other HAP emissions would not have 

addressed the EPA’s desire to promote, and give credit for, coal 

preparation practices that remove Hg and other HAP before firing 

because we did not have the data to account for those practices. 

Specifically, to account for the coal preparation practices, 
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sources would be required to track the HAP concentrations in 

coal from the mine to the stack, and not just before and after 

the control device(s). Such an approach would be difficult to 

implement and enforce. Moreover, we do not have the data 

necessary to establish percent reduction standards for HAP at 

this time. Depending on what was considered to be the “inlet”

and the degree to which precombustion removal of HAP was desired 

to be included in the calculation, the EPA would need (e.g.) the 

HAP content of the coal as it left the mine face, as it entered 

the coal preparation facility, as it left the coal preparation 

facility, as it entered the EGU, as it entered the control 

devices, and as it left the stack to be able to establish 

percent reduction standards. We do not have this type of 

information.

The EPA believes that an emission rate format allows for, 

and promotes, the use of pre-combustion HAP removal processes 

because such practices will help sources assure they will comply 

with the proposed standard. A percent reduction requirement 

would likely limit the flexibility of the regulated community by 

requiring the use of a control device. In addition, as discussed 

in the Portland Cement NESHAP (75 FR 55002; September 9, 2010), 

the EPA believes that a percent reduction format negates the 

contribution of HAP inputs to EGU performance and, thus, may be 
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inconsistent with the D.C. Circuit’s rulings as restated in the 

Brick case (479 F.3d at 880) which say, in effect, that it is 

the emissions achieved in practice (i.e., emissions to the 

atmosphere) that matter, not how one achieves those emissions.

The 2010 ICR data confirm that plant inputs likely play a 

role in emissions to the atmosphere. These data indicate that 

some EGUs are achieving lower Hg emissions to the atmosphere at 

a lower Hg percent reduction (e.g., 75 to 85 percent) than are 

other EGUs with higher percent reductions (e.g., 90 percent or 

greater). However, we are not sure whether these data accurately 

reflect the total percent reduction mine-to-stack because we do 

not have all the data necessary to make that determination. 

Thus, we proposed to establish numerical emission standards for 

Hg HAP emissions from EGUs and we are finalizing numerical 

emission standards. The same issues prevent us from considering 

percent reduction standards for the other HAP emitted from EGUs.

With regard to the comments relating to some state programs 

being more stringent than the EPA’s proposed limits, the EPA

would note that many of the programs identified by one commenter 

have an “either/or” format for their Hg standards. That is, an 

EGU can either meet an emission limit (e.g., lb/TBtu) or achieve 

a percent reduction. The commenter did not note which form of 

the standard the EGUs were meeting so it is unclear whether the 
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standards are in fact more stringent. In any case, CAA section 

112(d) does not mandate that federal standards be more stringent 

than state requirements for HAP emissions. Furthermore, states 

are authorized to establish standards more stringent than this 

final NESHAP so promulgation of this rule will in no way effect 

a source’s responsibility to comply with an otherwise applicable 

state Hg or other HAP standard.

9. Beyond-the-floor

Comment: Several commenters stated that the proposed beyond-thefloor Hg limit for low rank coal EGUs is based on too little 

data and is technically and economically unattainable, noting 

that the EPA’s proposed beyond-the-floor limit is based on only 

three samples from a single test held at only one EGU, which is 

not enough data to develop such a limit, especially as more data 

were available for this EGU in the database. Commenters noted 

that although this one EGU may have been able to achieve the 

proposed limit during this one test, the three samples are not 

adequate to demonstrate the long-term ability of this EGU to 

meet that limit consistently, let alone the long-term abilities 

of the top 12 percent of all low rank coal EGUs to meet that 

limit consistently. Given Texas lignite’s particularly high 

rates of variability of Hg concentration, and the inability to 

minimize this variability, the commenters believe that the EPA
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is obliged to have more, not less, data to support the proposed 

beyond-the-floor Hg limit for low rank coal EGUs. One commenter 

added that the EPA’s decision to require a beyond-the-floor 

limit for the low rank virgin coal subcategory does not comply 

with CAA section 112(d)(2). Some commenters also contended that 

the EPA failed to include the cost of a baghouse in its beyondthe-floor analysis. They note that, according to the EPA, in 

order to comply with the proposed EGU MACT rule, units will 

either fuel switch to a lower Hg fuel or retrofit air pollution 

controls.

Response: The EPA notes that all of the low rank virgin coalfired EGUs for which data were submitted in response to the 2010 

ICR were meeting the Hg floor limit (11 lb/TBtu). Four of the 

EGUs have ACI systems installed and three of the four EGUs 

tested were also meeting the beyond-the-floor Hg emission limit 

of 4.0 lb/TBtu. Those three units were achieving control levels 

of greater than 95 percent (fuel to stack). The other low rank 

virgin coal-fired EGUs that are not currently meeting the 

beyond-the-floor emission limit do not have installed Hgspecific controls. An analysis of the Hg content of the fuel 

used during the 2010 ICR testing suggests that control in the 

range of 80 to 90 percent (fuel to stack) would be needed to 

meet the beyond-the-floor limit of 4.0 lb/TBtu. One low rank 
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virgin coal-fired EGU achieved 75 percent control with no Hgspecific control technology (e.g., ACI).

The EPA believes that its beyond-the-floor analysis is 

appropriate, including the costs analyzed. The EPA’s cost 

analysis is meant to serve as an average for all sources in the 

subcategory recognizing that some EGU’s costs will be more and 

some less; EGUs whose costs are higher are not exempted from the 

regulation. Further, five EGUs in the subcategory are meeting 

the final beyond-the-floor limit based on available data (see

the MACT Floor analyses in the docket), and, in any case, CAA 

section 112(d) does not require that a specified percentage of 

sources in a category or subcategory be able to meet the MACT 

standard that is established. This is even truer for beyond-thefloor standards which are set at levels beyond what the average 

of the best performing sources are achieving in practice and 

instead based on what is achievable. Commenters have failed to 

provide any data that supports the contention that some EGUs in 

the subcategory will not be able to achieve the standards with 

additional controls.

Comment: Commenters indicated that the EPA has not justified a 

beyond-the-floor limit for Hg for new IGCC units. The EPA’s 

choice of the beyond-the-floor Hg limit for new IGCCs is not 

derived from IGCC test data from the 2010 ICR and commenters 
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allege that the EPA has not provided adequate justification for

its decision from a technology capability assessment. Commenters 

note that ACI for Hg treatment of coal-derived syngas is not in 

use in any operating IGCC plant today, nor can it be used in the 

same fashion as it is used at conventional coal-fired EGUs. 

Commenters assert that the EPA also lacks data with respect to 

new IGCC units, yet the EPA proposed beyond-the-floor MACT 

limits for new IGCC sources. The commenters assert that the 

EPA’s limits for new IGCC sources are based on beliefs, 

predictions, projections and design target assumptions. The 

limits from the 2007 DOE Report referenced in the preamble are 

based on environmental target assumptions. These IGCC 

environmental targets were chosen to match Electric Power 

Research Institute (EPRI) design basis from their Coal Fleet for 

Tomorrow Initiative. Commenter states that EPRI notes that these

were design targets and were not to be used for permitting 

values. Commenters assert that the EPA has simply not justified 

its process for going beyond-the-floor for new IGCC units and 

that, without sufficient justification, the EPA actions are 

unsupported.

Two commenters provided permit information, based on IGCC 

units currently under construction, for PM and Hg emissions. One 

commenter requested that the proposed new MACT floor limit for 
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PM be modified to address the two scenarios for duct burners at 

IGCC plants, syngas-fired and natural-gas-fired. The commenter 

requested the 0.050 lb/MWh limit be increased to at least 0.068 

lb/MWh based on gross energy output from the combined cycle 

generating unit when operated with duct burners fired with 

syngas. The 0.068 lb/MWh value is consistent with the calculated 

emission ceiling for its permit to construct for this operating 

scenario. According to the commenter, there is not sufficient 

experience with syngas turbines for manufacturers to guarantee 

performance in the 0.050 lb/MWh range. The 0.0681b/MWh 

performance basis proposed by the commenter was calculated based 

on the emission guarantees that the commenter was able to obtain 

for a turbine fired on the syngas. The commenter also requested 

that the 0.050 lb/MWh limit be increased to 0.083 lb/MWh based 

on gross energy output from the combined cycle unit when 

operated with duct burners fired by natural gas. The commenter 

indicated that, depending on market conditions, the syngas 

produced at an IGCC may have more value as a raw material for 

producing co-products than it would have as duct burner fuel. 

Where that is the case, the economic viability of an IGCC would 

be enhanced by firing the duct burners on natural gas and 

diverting that syngas to manufacture of a co-product. The 

commenter’s air permits are currently based on the use of syngas 
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as duct burner fuel; however, the commenter is currently 

examining an alternative operating scenario that may result in 

amendments to the air permits to authorize firing natural gas in 

the duct burners. Commenter states that preliminary calculations 

indicate that the PM limit would need to be set at 0.083 lb/MWh 

gross energy output when operated with duct burners fired with 

natural gas.

The commenter also noted that there is not sufficient test 

data to precisely predict the Hg emissions performance of even 

the best-controlled IGCC units, other than that IGCC Hg 

emissions are expected to be much less than those for EGUs that 

directly burn coal. In its permit application, the commenter 

proposed to establish a new standard for Hg removal in IGCC 

units by treating the syngas in catalytic reactors. The 

catalytic reactor system is expected to achieve greater than 95 

percent Hg removal using either sulfur-impregnated activated 

carbon or alumina catalyst. In the absence of actual stack test 

data, the commenter has had to estimate expected emissions based 

on engineering estimates of how much Hg may arrive in the syngas 

routed to the catalytic reactors. Based on these engineering 

estimates and 95 percent Hg removal in the catalytic reactors, 

the commenter believes that the resulting Hg emission limit for 

a state-or-the-art IGCC unit would be 0.003 lb/GWh, which is 
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much less than the Hg emissions for EGUs that directly burn 

coal.

The commenter notes that IGCC units are still in their 

infancy. Funding for them will be very difficult or unavailable

if there is a regulatory limit below the level that can be 

supported by vendor guarantees. Given the important role that 

IGCC units may have in meeting global energy and climate 

stability goals, the commenter believes it would be a mistake to 

erect barriers to the implementation of this technology. The 

commenter stated that the EPA can reevaluate the appropriate 

levels for future IGCC units after demonstration units which 

incorporate effective controls have been built and tested.

Response: The EPA is not finalizing the proposed new source

standards for IGCC units. As commenters noted, EPA proposed 

beyond-the-floor limits for IGCC units based on the performance 

of PC-fired EGUs and solicited data from IGCC units that would 

represent what a new IGCC could achieve. We received information 

that there are new IGCC units permitted and under construction. 

The EPA believes one IGCC unit under construction for which 

permit data were provided is representative of both current 

technologies and of IGCC units that will be built in the nearterm future. Therefore, the EPA believes these permit levels 

should be the basis of the new source IGCC emission limits and 
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the Agency is finalizing the PM and Hg limits on that basis, as 

that source will be required to comply with its permitted limits

once constructed and it is a similar source. However, permit 

limits were only provided for PM and Hg; therefore, the EPA is 

finalizing the new source limits for acid gas HAP based on data 

from the best-performing of the existing IGCC units for the 

respective HAP.

B. Rationale for Subcategories

Many commenters stated that the EPA should have proposed 

more subcategories, while others believed that too many 

subcategories were proposed. Many different issues were raised

by commenters, and some of the key issues that were considered 

in the final rule (some of which led to changes in the final 

rule) include: the technical deficiencies in the definition for 

the low-Btu coal subcategory; additional subcategorization of 

the coal-fired EGU population; the need for subcategorization of 

distillate vs. residual oil-fired EGUS; the need for a limiteduse subcategory for EGUs that operate for only a small 

percentage of hours during a year; and the need for a noncontinental liquid oil subcategory for island units that have 

limited fuel options and other unique circumstances. The 

comments and the EPA responses are provided below.

In general, the EPA has reviewed the data provided and 
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continues to believe that the coal-fired EGU subcategories 

proposed are the only ones supported by the data, though we have 

revised the basis for EGUs designed to burn low rank virgin coal

as discussed above. The EPA may not subcategorize by air 

pollution control technology type as requested by a few 

commenters. Further, the EPA has reviewed the other suggested 

coal-fired subcategories and finds no basis for further 

subcategorization (e.g., based on boiler design, boiler size, or 

duty cycle).

1. Coal Subcategories

Comment: Commenters noted that although other subcategories had 

been evaluated, including subcategorization of other coal ranks, 

no other coal rank subcategorization was proposed. Commenters 

submit there should be subcategories for the coal ranks of 

bituminous, subbituminous, and lignite. The commenters noted 

that such treatment would be consistent with past practice 

(e.g., CAMR where the differences in the type of emissions of Hg 

due to the different chemical properties of coal within 

differing fuel ranks was discussed). Commenters note that 

activated carbon has been shown to be very effective when used 

in combination with low chlorine coals (such as western 

subbituminous coals); however, activated carbons can suffer from 

poor performance when used with high sulfur coals. Commenters 
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indicate that firing high sulfur coals (especially when an SCR 

is also used) can result in sulfur trioxide (SO3) vapor in the 

flue gas stream. The SO3 competes with Hg for binding sites on 

the surface of the activated carbon (or unburned carbon) and 

limits the effectiveness of the injected activated carbon. But 

another commenter noted that an SO3 mitigation technology, such 

as dry sorbent injection (DSI, e.g., trona or hydrated lime), 

applied upstream of the ACI can minimize this effect.

Commenters also stated that without further 

subcategorization the economic impacts on individual Midwestern 

states will be particularly acute as huge segments of the U.S. 

coal reserve will be disenfranchised by this rule. According to 

the commenters, the EPA did not even attempt to legitimately 

analyze this issue and, thus, in their opinion the Agency’s 

proffered rationale for declining to further subcategorize based 

on the acid gas standard is belied by the record. The commenters 

believe that the EPA needs to better align this rule with its 

previous position in CAMR and further subcategorize based on 

coal type.

Other commenters are opposed to any further 

subcategorization based on coal rank. Because many sources blend 

several ranks of coal on a regular basis, commenters believe 

that establishing coal rank subcategories would create numerous 
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opportunities for sources to game the regulations and 

substantially increase emissions. Commenters stated that there 

is no need for such an approach since modern pollution controls 

can accommodate a wide range of coals. These commenters believe 

that EGUs firing different ranks of coal are not fundamentally 

different in size, class, or type in a way that impacts 

emissions or that limits the availability of controls. The 

commenters believe that emissions of fuel-dependent HAP can be 

controlled by either changing the fuel prior to combustion or by 

removing the HAP from the flue gas after combustion. Commenters 

state that ACI systems, DSI controls, and PM controls are 

available for installation at units firing sub-bituminous coal 

and are equally available for units firing bituminous, 

anthracite, or lignite coal. These commenters also believe that 

as long as a control option is commercially available, the cost

for a particular EGU is irrelevant to the EPA’s development of 

emission standards based on MACT. Commenters stated that 

subcategories based on coal rank would make a meaningful 

consideration of fuel switching impossible, contrary to the 

judicial mandate to consider substitution of materials in 

setting the floor and the statutory mandate to consider 

substitution of materials in the beyond-the-floor analysis.

One commenter stated that although they previously 
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supported the subcategorization of coal-fired units on the basis 

of coal rank, they no longer object to grouping units that burn 

bituminous and subbituminous coals in a single category because 

the prior basis for subcategorization no longer exists. The 

commenter indicated that at the time of CAMR, it was widely 

recognized that although coal-fired units combusting bituminous 

coal, with its higher concentration of chlorine and, therefore, 

ionic Hg, could effectively limit Hg emissions by utilizing 

existing control technologies such as scrubbers, units burning 

subbituminous coal could not do so with the same controls 

because of the coal’s higher levels of elemental Hg. The 

commenter stated that activated carbon was only a fledgling and 

unproven technology at the time; today, however, activated 

carbon has been proven, and units burning bituminous and 

subbituminous coal can achieve the same levels of emissions for 

Hg and other HAP. Consequently, the commenter believes the prior 

basis for subcategorization no longer exists and the commenter, 

therefore, agrees that coal-fired EGUs burning bituminous and 

subbituminous coals ought to be grouped in a single category.

Response: The EPA disagrees with commenters that additional 

coal-fired subcategories are warranted and has not provided any 

in the final rule. Commenters are correct that additional 

subcategorization was proposed in January 2004. Whether or not 
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such subcategorization was warranted at that time, the EPA

believes that the current conditions are such that, even if 

appropriate at that time, such further subcategorization is not

appropriate at this time.

When all of the factors noted by commenters have been 

reviewed, with the exception of Hg for certain units, as 

discussed above, the EPA does not believe that the HAP emissions 

to the atmosphere are sufficiently different from coal-fired 

EGUs to warrant further subcategorization. There are EGUs firing 

bituminous, subbituminous, and coal refuse among the top 

performing units for Hg and EGUs firing bituminous, 

subbituminous, lignite, and coal refuse are all among the top 

performers for the acid gas HAP and non-mercury metallic HAP 

indicating that the MACT floor limits established based on these 

units are achievable by units burning all ranks of coal.

As noted by commenters, ACI, not fully developed in 2004, 

is now able to effect Hg control levels on subbituminous coals 

such that similar emissions to the atmosphere may be achieved as 

those achieved by higher-chlorine bituminous coals when FGD 

systems are used or by coal refuse EGU with less controls. Thus, 

in looking at the total system, similar emissions to the 

atmosphere are achieved by all of these coal ranks. The EPA has 

addressed elsewhere in this document its rationale for not 
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subcategorizing by coal chlorine content. The EPA does not 

believe that any fundamental discrimination between coal ranks 

will occur as a result of the final rule, though clearly some 

sources will be required to install greater controls to comply 

with the final standard. We maintain that such result is 

consistent with the intent of CAA section 112 standards, which 

are not intended to have an outcome whereby all sources can 

comply with final standards without any action.

The EPA agrees, in theory, that EGUs are designed around a

basic set of coal characteristics. However, the 1999 ICR

demonstrated that numerous EGUs have conducted trial burns and 

gained sufficient experience such that co-firing blends of 

various coal ranks is now common practice. In fact, the EPA

believes that such blends may be modified daily, depending on 

the characteristics of the coal being burned and on the level of 

generation needed. The extent of blending, and the ability to 

switch the blends on short-notice, does not lend itself (or, in 

fact, argue for) additional subcategorization.

The EPA disagrees with any assertion that the EPA ignored 

possible subcategorization approaches or that it has 

insufficient data upon which to base or evaluate various 

subcategories. The EPA fully examined the record, which 

demonstrates that coal-fired EGUs, with the exception of certain 
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units for Hg, have similar HAP emissions profiles and that 

similar control approaches are available to such EGUs. Although 

commenters suggested additional subcategories were warranted, 

they failed to provide sufficient data to support their proposed 

alternative subcategories. As noted elsewhere, the EPA does not 

disagree with commenters that there are some differences in 

EGUs. However, the EPA does disagree with commenters that those 

differences result in differences in emissions to the atmosphere 

such that additional subcategorization is justified.

Failing to demonstrate that coal-fired EGUs are different 

based on emissions, the commenters turn to economic arguments, 

asserting that failing to subcategorize will impose an economic 

hardship on certain sources. Congress precluded consideration of 

costs in setting MACT floors, and it is not appropriate to 

premise subcategorization on costs either. See S. Rep No. 101-

228 at 166-67 (5 Legislative History at 8506-07) (rejecting the 

implication that separate categories could be based on 

“assertions of extraordinary economic effects”); see also NRDC

v. EPA 489 F.3d 1364 (D.C. Cir. 2007) (holding that EPA properly 

declined to create a subcategory for a particular source and 

rejecting the argument that the source may have to incur more 

costs to comply with the rule without such subcategory). 

The final limits are based on EGUs currently operating with 
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available controls. As noted above, the record shows that the 

various types of EGUs are represented in the floors, with the 

exception of certain units for Hg, which indicates that the 

levels are achievable by such units. Thus, the data actually 

show that the MACT standards are achievable for a wide variety 

of EGUs.

In addition, the EPA believes it has fulfilled the CAA 

section 112(c)(l) directive that “[t]o the extent practicable, 

the categories and subcategories listed under this subsection 

shall be consistent...” with those of CAA section 111, 

notwithstanding commenters assertion to the contrary. The 

decision on whether to directly align CAA sections 112 and 111 

subcategories is discretionary and EPA has reasonably exercised 

its discretion in declining to create additional subcategories

for coal-fired EGUs based on the record, with the exception of 

certain sources for Hg.

Finally, the EPA disagrees with the commenters that suggest 

that EPA lacks the legal authority to consider material inputs 

when considering subcategories. We agree, however, that material 

inputs must be considered when establishing MACT standards for 

the subcategories that are established. We also believe a 

meaningful consideration of fuel switching can occur even if 

sources are subcategorized based on fuel inputs because EPA 
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considers fuels switching in evaluating potential beyond-thefloor alternatives.

Comment: One commenter stated that the EPA should establish an 

existing source acid-gas subcategory for high sulfur or high 

chlorine coals because the same factors that the EPA relied on 

to support a low rank virgin coal subcategory for Hg are also 

present in the high sulfur or high chlorine coal context. The 

commenter stated that the data indicate that even wellcontrolled units burning high sulfur coals would not be in the 

top performers for acid gases even at removal rates of 95 or 96 

percent. The commenter added that absent such a subcategory, 

about 12 percent of coal deliveries (2005 data), and the vast 

majority of coal shipped from the states of Indiana, Ohio, and 

Illinois (2008 data), would become unusable. The commenter 

expressed support for the alternative SO2 standard for units 

unable to meet the HCl standard; however, the commenter also 

believed that it is appropriate to establish a coal chlorine or 

sulfur content-based subcategory for the alternative SO2

standard. The commenter stated that coal testing data indicate a 

clear break in chlorine concentrations in the coals burned by 

EGUs, as well as in sulfur content. The commenter indicated that 

there are factors supporting a high sulfur or high chlorine coal 

subcategory that are similar to those that the EPA relied upon 
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to support a Hg subcategory for low rank virgin coal. According 

to the commenter, the EPA’s key rationale for a Hg subcategory 

for low rank virgin coal was that no low rank virgin coal-fired 

unit appeared in the “top performing 12 percent of sources, 

indicating a difference in the emissions for this HAP from these 

types of units.” The EPA did not establish other subcategories 

because “the data did not show any difference in the level of 

HAP emissions and, therefore, we have determined that it is not 

reasonable to establish separate emissions limits for other 

HAP.” The commenter indicated that the EPA does not need 

emissions data to know that even well-controlled units burning 

higher sulfur coals would be unable to meet the alternative SO2

emissions rate, and would therefore also not appear in the top 

12 percent of performing units.

Response: The EPA disagrees with commenters that subcategories 

should be established for high sulfur and high chlorine coals. 

It appears from the comments that it is not in fact the chlorine 

content that is at issue but the sulfur content of the coal. 

Commenters state that they are unable to meet the HCl limit, but 

they only provide information indicating it would be difficult 

to meet the alternative equivalent SO2 limit. In fact, our data 

show that coals with chloride contents as high as 2,100 ppm 

(0.16 lb/MMBtu) were burned by EGUs making up the MACT floor 
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pool of sources for the final HCl emission limit and that the 

best-performing unit was burning coal with a maximum chloride 

content of 1,200 ppm. The median chloride level for bituminous 

coals identified from data submitted through the 1999 ICR was 

1,030 ppm so we believe that the coals represented in the MACT 

floor pool indicate that the final limits are achievable with 

high-chlorine coals. We have determined that HCl removal is very 

effective using a number of different types of FGD systems. 

Absent information demonstrating that sources are unable to meet 

the proposed HCl limit due to the chlorine content of the coal, 

we believe it is unnecessary and inappropriate to consider 

subcategorizing based on chlorine content in the coal.

In addition, as noted above, the SO2 limit is an alternative 

equivalent standard that is available to sources that have an SO2

control and CEMS and operate the controls at all times. The EPA 

did not provide the alternative equivalent standard for sources 

that could not meet the HCl limit as one commenter suggests; 

instead, we provided the standard as a convenience and cost 

saving measure to EGUs with installed FGD systems because we 

recognize that many EGUs have SO2 CEMS. Sources are required to 

comply with the HCl limit as a surrogate for all the acid gas 

HAP or the SO2 limit as an alternate equivalent standard. 

Commenters have not demonstrated that they are unable to meet 
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the HCl standard and our data show that the standard is 

achievable even for high chlorine coals.

Comment: Several commenters supported the development of a 

separate subcategory for fluidized bed combustors (FBC) or 

circulating fluidized bed (CFB) EGUs. The commenters encouraged 

the Agency to consider subcategorization of FBC EGUs for Hg 

emissions noting that the industry has long contended that the 

design, construction, and operation of FBCs are different than 

conventional boilers and that FBCs employ fundamentally 

different processes than conventional PC-fired EGUs. The 

selection of an FBC unit over a conventional PC boiler is driven 

in large part by fuel characteristics. The commenters assert 

that, as a result, the emissions profile of FBC units generally 

differ from conventional PC boilers because FBC units more 

advantageously combust waste coals, as well as coal blends with 

other carbonaceous material. The commenters stated that the EPA

did not discuss the design differences between FBC units and PC 

units in the preamble to this proposed rule unlike what the 

Agency did when it previously proposed Hg MACT limits in January 

2004. Commenters state that, for these reasons, FBC units can be 

considered a distinct type of boiler.

The commenters noted that an examination of the 40 “best 

performing” units for Hg emissions in the proposed MACT floor 
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spreadsheet showed that 14 of those units are FBC units. The 

commenters maintained that had FBC units performed as well as

conventional PC boilers, 2 units would have been expected to be

in the top 40. The commenters allege that the far higher 

percentage of FBCs in the top 40 leads to the conclusion that 

these units are different from conventional PCs with regard to 

Hg emissions and, as a result, should have been placed in their 

own subcategory. Further, commenters noted that the largest FBC 

has a nameplate capacity of about 300 MW while the largest 

conventional boilers have nameplate capacities of around 1,300 

MW.

The commenters stated that FBCs combust relatively large 

coal particles in a bed of sorbent or inert material at a lower 

degree of combustion efficiency. Fluidized bed units operate at 

less than half of the temperature of a conventional boiler and 

have much longer fuel residence times. Conventional boilers 

pulverize coal to a very fine particle size to maximize 

combustion efficiency and minimize unburned carbon. As a result, 

the commenters noted that FBCs typically have higher levels of 

unburned carbon present in the ash, which behaves much like 

activated carbon and helps promote more efficient Hg removal. 

Accordingly, commenters maintain that Hg emissions of FBC 

boilers and PC boilers are statistically different, with 
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emissions from FBCs significantly lower than those from PC 

boilers. According to commenters, this statistically significant 

difference in the Hg emissions profiles for these two distinct 

boiler technologies argues in favor of the creation of a 

separate subcategory for FBCs, as there is no control technology 

that PCs could install that would result in emissions reductions 

similar to those achieved by FBCs. The active quantity of 

calcium oxide (lime-CaO) available in a FBC boiler is also 

orders-of-magnitude greater than compared to a PC boiler, whose 

alkalinity is derived solely from the coal’s mineral content. 

Significantly higher CaO can alter the process chemistry in the 

boiler, including the oxidation levels of Hg.

One commenter stated that the EPA properly declined to 

subcategorize units based on design type where there is no 

indication that any physical distinctions among unit designs 

have a meaningful and substantial impact on HAP emissions. The 

commenter indicated that it would be inappropriate to 

subcategorize FBCs because there is no evidence to support a 

determination that FBC design is responsible for a unit falling 

in or out of the top 12 percent for a particular HAP.

Response: The EPA acknowledges that there are design and 

operation differences between conventional PC-fired EGUs and 

FBC/CFB EGUS; however, the commenters are incorrect in asserting 
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that the HAP emissions levels and characteristics are 

sufficiently distinct from other coal-fired EGUs to support 

subcategorization. Further, commenters fail to note that FBC 

EGUs were not subcategorized in CAMR even though, as commenters 

note, such design and operation differences were cited there. 

The fact that FBC units operate at lower temperatures is of no 

consequence as they still operate at temperatures high enough to 

vaporize Hg.

Commenters assert that FBC units are disproportionately 

represented among the best performers, with the inference being 

that they were selected to test in the 2010 ICR because of their 

boiler design. However, FBC EGUs were not specifically selected 

as best performers for Hg, as EPA did not select any EGUs based 

on a determination that they were best performers for Hg (as 

noted elsewhere, we had no basis for selecting EGUs as being 

best performers for Hg), and to the extent CFB units were 

selected in the 2010 ICR, they were selected because we 

determined they were best performers for non-mercury metallic 

HAP, acid gas HAP, or organic HAP or because they were randomly 

selected among the non-best performers for those three HAP 

groupings. Thus, the CFBs were selected for testing under the 

2010 ICR based not on their boiler design but, rather, based on 

the age and on their PM and FGD control systems (as noted in the 
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Supporting Statement for the 2010 ICR). As many FBC EGUs, 

including CFB EGUs, are relatively new, they were included in 

the non-mercury metallic HAP group selected for testing (because 

their PM controls were among the 175 newest), the acid gas HAP 

group selected for testing (because FBC was considered to be an 

FGD system and the units were among the 175 newest), and organic 

HAP testing (because they were among the newest and, thus, 

determined to be among the most efficient).

The effect on Hg emissions is not what commenters suggest 

because, although, as noted by commenters, FBC units may be 

found among the better performers (among the top 10 EGUs) on the 

Hg MACT floor spreadsheet, they are also found in the range of 

221 to 226 EGUs (of 393 data points). The fact that FBC units 

have “vastly dissimilar ash properties” that may contain higher 

levels of lime or unburned carbon in the fly ash than 

conventional PC EGUs does not indicate that the overall system 

behaves any differently with regard to emissions to the 

atmosphere (the key metric) than a conventional PC EGU with addon controls. The asserted higher levels of unburned carbon 

result in a range of effectiveness of Hg control that is similar 

to that of ACI found on PC EGUs; such ACI control may be found 

on EGUs that are among the better performers as well as on EGUs 

as low as 369 on the list of data points. Thus, the EPA
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disagrees that FBC units are disproportionately represented in 

the Hg floor and that their inclusion is somehow inappropriate 

or leads to skewing of the analysis.

All types of coal-fired EGUs other than those we 

subcategorized are represented in the MACT floors for Hg and all 

types of EGUs are represented in the floors for the non-mercury 

HAP. Fluidized bed combustion EGUs are not an exception and such 

EGUs are found across the range of top performing EGUs for all 

of the HAP categories: acid gas, non-mercury metallic, and Hg. 

In addition, any assertion that non-FBC EGUs are unable to meet 

the final standards because FBC EGUs are included in the same 

subcategory (or vice versa) is plainly refuted by the fact that 

EGUs of all types are currently meeting one or more of the final 

standards. Thus, the EPA finds no basis for subcategorizing FBC 

EGUs.

Further, as noted below, the EPA does not believe there is 

a basis for subcategorizing small EGUs, either FBC or PC. In 

addition, the data have been re-evaluated based on comments 

received and an FBC unit is not the basis for the new source Hg 

MACT floor.

Comment: Many commenters stated that the EPA should have 

considered additional subcategorization schemes, including one 

based on EGU size. Commenters noted that one of the factors that 
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the Administrator can consider under CAA section 112(d)(1) in 

making subcategorization decisions is unit size. Commenters 

stated that an analysis of the 2010 ICR data showed a 

statistical difference between EGUs with a capacity of 100 MW or 

less and EGUs above 100 MW; other commenters suggested that the

cut-off range should be 125 MW. Although large in number (about 

27 percent) of all EGUs, these small EGUs only comprise about 5 

percent of the coal-fired capacity in the U.S. Thus, commenters 

assert that if different MACT limits are set for this 

subcategory of EGUs, it will not have a significant impact on 

the health effects of HAP emissions. Commenters noted that 

although emission rates from such small EGUs are greater than 

those found in the large unit fleet, their contribution to the 

total EGU emissions is not significant. The costs associated 

with coming into compliance with the proposed rule by installing

new controls would be proportionally much higher for these small 

EGUs than larger EGUs according to the commenters. The 

commenters allege that this would force the retirement of 

generation capacity and threaten electrical reliability without 

appreciable benefit to the environment.

One commenter stated that in general, the nature of many 

public power facilities differs from the general population of 

coal-fired power plants. Public power units tend to be smaller 
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in size, and are often space-constrained by growth in the 

community surrounding the generating unit since its initial 

construction. These limitations restrict the ability of these 

EGUs to achieve the same performance levels of larger, 

unconstrained EGUs; and, for those EGUs that can comply with the 

proposed standards, the installation of controls sharply 

increases the cost of compliance. The commenter stated that the 

EPA did not adequately subcategorize to accommodate many smalland medium-sized public power utilities. In particular, the EPA

did not avail itself of the opportunity to use a public power 

electric utility subcategory, rural subcategory, or fuel type 

subcategories. Other commenters endorsed the establishment of a 

less than 100 MW subcategory that would reduce the costs of the 

proposed rule significantly, but only affect 5 percent of the 

total electric utility sector, and help minimize retirement of 

uneconomical plants.

One commenter stated that the EPA properly recognized that 

subcategories based on unit size would be inappropriate because 

the proposed emission limits are in terms of lb/MMBtu or lb/TBtu 

and noting that an EGU’s total nameplate capacity is wholly 

unrelated to its ability to achieve the proposed limits. Another 

commenter opposed any proposal to subcategorize units below 100 

MW. The proposed rule does not apply to units less than or equal 
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to 25 MW, and this commenter believed that this is a sufficient 

threshold for applicability.

One commenter stated that the EPA could establish 

subcategories for the purpose of temporarily exempting, for 

example, a subcategory of utilities that meet the definition of 

small entity for purposes of the proposed rule. The temporary 

exemption would sunset on a date certain (e.g., 3 years from the 

effective date of the rule) at which point the sources in the 

subcategory would become subject to the rule, and a compliance 

timetable would start to run. The commenter believed that this 

time-staged promulgation and compliance proposal would greatly 

increase the chance that the control measures could be added in 

an orderly and efficient manner with minimal disruption to power 

markets and grid reliability.

Response: The EPA agrees with commenters who stated that an 

EGU’s size is totally unrelated to its ability to comply with 

the final concentration-based limits. The EPA examined the size 

of units within the respective MACT floor pools of sources and 

found units ranging in size from 25 to 1,320 MW in the HCl floor 

pool, from 25 to 869 MW in the non-mercury metallic floor pool, 

and from 47 to 544 MW in the Hg floor pool. Thus, we find no 

more difference between a 25 MW EGU and (e.g.) a 500 MW EGU than 

we do between a 500 MW EGU and a 1,300 MW EGU and reaffirm our 
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position that the MW capacity of the EGU is not a determining 

factor in its emissions. Further, the EPA believes that units of 

all sizes are owned by both large and small entities.

The EPA examined the effect if EGUs less than 125 MW were 

subcategorized for Hg. The resultant MACT floor for these EGUs 

would be 1.0 lb/TBtu on a 30-boiler operating day rolling 

average, a level more stringent than that developed for the 

>8,300 Btu subcategory as a whole. We do not believe that this 

is what commenters envisioned when suggesting such a subcategory 

but we believe it confirms our analysis of the data that 

indicates, as noted, these units are controlled in the same 

manner as other, larger EGUs, such that additional 

subcategorization is not necessary or reasonable. Further, based 

on the number of EGUs less than 125 MW in the HCl and PM MACT 

floor pools, we believe that a similar analysis for HCl and PM 

would lead to similar or more stringent standards than without 

the additional subcategory. Thus, units of all sizes are capable 

of achieving the proposed limits and the EPA is not finalizing a 

subcategory based on unit size in the final rule.

The CAA authorizes EPA to subcategorize based on “classes, 

types, and sizes of sources.” The EPA does not believe that this 

provision permits subcategorizing sources based solely on their 

status as small entities for several reason. As a threshold 
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matter, commenters provided no information to suggest that EGUs 

at small entities are different from EGUs owned by other 

entities. Instead, the commenters’ justification for such a 

subcategory was that the costs to comply with the standards make 

it more difficult for small entities; thus, the basis is 

essentially a cost basis and we do not think that is consistent 

with the statute. Moreover, the legislative history of CAA 

section 112(d) supports EPA’s interpretation that subcategories 

cannot be based on the cost of compliance. See S. Rep No. 101-

228 at 166-67 (5 Legislative History at 8506-07) (rejecting the 

implication that separate categories could be based on 

“assertions of extraordinary economic effects”). 

In addition, the EGUs owned by small entities use the same 

type of fuel as other units, have the same type of combustor 

designs, and can use the same types of controls, and so there is 

no difference in the HAP emissions from such units. So, even if 

we believed a subcategory based on small entities was consistent 

with the statute, we would decline to include such a 

subcategory.

Therefore, given the language of CAA section 112(d), the 

legislative history, and the available information, EPA is not 

creating a separate subcategory for EGUs owned by small 

entities.
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In addition, the D.C. Circuit has clearly stated that the 

EPA does not have the statutory authority under CAA section 112 

to extend compliance dates past the 3-year maximum compliance 

time authorized in CAA section 112(i)(3)(A) except consistent 

with CAA sections 112(i)(3)(B) and 112(i)(4). See NRDC v. EPA, 

489 F.3d 1364, 1374 (D.C. Cir. 2007)(finding that “Congress 

enumerated specific exceptions to the 3-year maximum, which 

indicates that Congress has spoken on the question and has not 

provided the EPA with authority under subsection 112(i)(3)(B) to 

extend the compliance date...”) (citing also CAA section 

112(i)(4)). The EPA may not alter the compliance date based on 

size or ownership considerations and, thus, we are not providing 

a separate compliance date for different groups of EGUs in the 

final rule.

Comment: One commenter stated that the EPA should establish a 

subcategory consisting of EGUs that had received air 

construction permits but had not yet commenced construction as 

of the date of the EPA’s proposed rule. The commenter believed 

that such a category would be justified because a substantial 

amount of time, money, and effort has been invested in these 

units. The commenter asserted that imposing new source standards 

on these EGUs for which the EPA’s proposed rule had not been 

anticipated during their permit consideration would unreasonably 
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and arbitrarily impose additional costs and burdens on these 

projects and would likely threaten the viability of many of 

them. The standards for this subcategory would be based on the 

anticipated performance of these units (as reflected by the 

permitted case-by-case emission levels), ensuring a reasonable 

and appropriate level of HAP control without unreasonably and 

arbitrarily interfering with the development of these units.

Response: Clean Air Act section 112(a)(4) defines a new source 

as “a stationary source the construction or reconstruction of 

which is commenced after the Administrator first proposes 

regulations under this section establishing an emission standard 

applicable to such source.” The EPA’s regulations implementing 

the CAA section 112 General Provisions define “commenced” to 

mean “with respect to construction or reconstruction of an 

affected source, that an owner or operator has undertaken a 

continuous program of construction or reconstruction or that an 

owner or operator has entered into a contractual obligation to 

undertake and complete, within a reasonable time, a continuous 

program of construction or reconstruction.” See 40 CFR 63.2.

The EPA is constrained by the definition of “new source”

such that any source that “commenced” construction after the May 

3, 2011, proposal date is considered a new source under the 

statute and the source must comply with the new source standards 
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even if the source received a final and legally effective CAA 

section 112(g) permit before proposal. It is unclear from the 

comments whether the sources identified in the comments have 

commenced construction as defined in the regulations; however, 

the identified sources are existing sources, not new sources, 

under the final rule if construction was commenced prior to the 

proposal date. 

Under the final rule, new sources must comply with the 

standards on the date of promulgation or at startup, whichever 

is earlier, and existing sources have 3 years to come into 

compliance with the final standards. Pursuant to the EPA’s 

regulations at 40 CFR 63.44(b)(1), however, we may provide in a 

final CAA section 112(d) standard a specific compliance date for 

those sources that obtained a final and legally effective CAA 

section 112(g) case-by-case MACT standard and submitted the 

information required by 40 CFR 63.43 to the Agency before the 

close of the comment period. The EPA does not believe it has 

received such information during the comment period and we are 

not establishing a separate specific compliance period for 

sources that obtained final and legally effective CAA section 

112(g) standards prior to promulgation of the final rule. In the 

absence of EPA action on this issue, state Title V permitting 

authorities are required to “establish a compliance date in the 
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[title V] permit that assures that the owner or operator shall 

comply with the promulgated standard [ ] as expeditiously as 

practicable, but not longer than 8 years after such standard is 

promulgated...” 40 CFR 63.44(b)(2). Sources with final and 

legally effective section 112(g) standards should work with 

their permitting authorities to determine the appropriate 

compliance date consistent with the EPA regulations.

Comment: One commenter stated that in accordance with CAA 

section 112(d)(l), based on the government-to-government 

relationship of the Navajo Nation and the U.S. government, and 

consistent with the right of sovereignty and self-determination 

of the Navajo Nation, it may be appropriate to classify EGUs on 

tribal lands in a different subcategory from those on non-Indian 

lands. The commenter stated that in accordance with the 

distinctive status of Indian lands, based on principles of 

tribal sovereignty and self-determination, the government-togovernment relationship, and the flexibility of federal agencies 

mandated under E.O. 13175, the EPA should classify sources on 

tribal lands as a unique subcategory of EGUs for which emission 

standards for NESHAP should be set pursuant to CAA section 

112(d)(3).

Response: Pursuant to CAA section 112(d)(1), the EPA may 

subcategorize sources based on differences in class, type, or 
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size. In the preamble to the proposed rule, the EPA further 

explains that any basis for subcategorizing (e.g., class) must 

be related to an effect on emissions, rather than some 

difference which does not affect emissions performance. The EPA 

does not agree that a subcategory based on location on Tribal 

lands is consistent with the statutory authority to 

subcategorize, and commenters do not explain why emissions would 

be different for EGUs located on Tribal lands. Absent that 

showing, EPA believes it would not be appropriate to 

subcategorize units even if we believed such a subcategory is 

consistent with the statute. CAA section 112 imposes specific 

requirements with respect to the methodology that the EPA must 

use in establishing emission standards for HAP, including Hg 

emissions from EGUs. Pursuant to CAA section 112(d)(1), the EPA 

may subcategorize sources based on differences in class, type, 

or size. The EPA believes, that any basis for subcategorizing 

(e.g., class) must be related to an effect on emissions, rather 

than some difference which does not affect emissions 

performance.

However, the EPA is sensitive to the commenters’ concerns 

and particularly recognizes the significance of Navajo 

Generating Station to the Central Arizona Project and the water 

delivery to tribes. As a result, EPA has been consulting with 
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affected Indian tribes and working closely with other federal 

agencies, including the Department of the Interior, on these 

issues and intends to work with tribal and other authorities to 

ensure a smooth transition and address specific issues as they 

arise.

2. Oil Subcategories

Comment: Several commenters stated that distillate oil, and in 

particular ultra-low sulfur diesel (ULSD) oil, has fuel 

characteristics closer to that of pipeline gas than to residual 

oils. The metals, as well as the ash and nitrogen content, of 

distillate oils are very low, and the sulfur content of ULSD is 

approximately the same as that of pipeline natural gas. The 

commenters state that distillate oil is a more refined product 

than residual oil and, thus, burns cleaner. According to 

commenters, separating liquid oil-fired EGUs into two 

subcategories (distillate and residual oil) would be consistent 

with the discussion of subcategory differentiation in the rule’s 

preamble which indicates that the division of a category into 

subcategories is justified if the two subcategories have very

different emissions, which is true for distillate vs. residual 

oils. Distillate and residual oils are also differentiated by 

their operating requirements. Some commenters stated that as a 

consequence of the mechanical differences between boilers 
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designed for residual oil vs. distillate oils, and between the 

fuel-handling requirements for the different fuels, it is not 

possible to interchange oil types without significant 

modifications to the oil storage tanks, transfer pumps, piping 

and valves, flow control systems, burners, and burner control 

systems. Commenters also noted that some of the EGUs in the 

EPA’s liquid oil-fired database were mischaracterized with 

regard to the type of oil burned during the 2010 ICR testing.

Some commenters alleged that by combining distillate and 

residual oil into a single MACT category, the resultant MACT 

standards cannot be satisfied by a boiler firing residual oil 

without substantial add-on controls. The commenters asserted 

that creation of separate subcategories for liquid oil-fired 

units that distinguish between residual and distilled oil would 

render the standards more achievable for distinct subcategories 

of EGUs and reduce the number of potential plant closures while 

still advancing the goal of reducing overall emissions. These 

commenters contend that MACT floors should not be used to 

eliminate whole classes of existing EGUs through mathematical 

floor calculations based on data from uncontrolled units and 

combining boiler subcategories that are not capable of 

accommodating a different fuel.

One commenter stated that the EPA should not subcategorize 
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liquid oil-fired EGUs based upon different grades of liquid oil. 

Although different grades of liquid oil may vary in their heat 

contents or viscosities, the commenter maintained that there is 

no indication in the rulemaking record that any physical 

distinction among units burning different grades of liquid oil 

affects the nature or characteristics of emissions in a way that 

impacts the availability of controls. According to the 

commenter, both distillate and residual oil-fired units can 

apply similar control technologies to reduce HAP emissions, and 

EGUs firing these fuels do not have physical distinctions that 

prevent controls from operating effectively. The commenter 

believes that fuel switching is an appropriate control 

technology and is available for liquid oil-fired sources. 

Residual fuel oil contains higher levels of contaminants, 

including HAP, than distillate oil, and because a regulated 

entity can readily burn cleaner distillate oil in lieu of 

residual oil, it is inappropriate to subcategorize based on the 

distillation fraction of the liquid oil. Thus, according to the 

commenter, the grade of liquid-oil fuel does not provide a 

reasonable basis for subcategorizing various groups of liquid 

oil-fired EGUs. Another commenter alleges that the EPA did not 

list distillate oil-fired EGUs in the 2000 Finding. 

Response: The EPA has reviewed the data and determined that it
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is not necessary to subcategorize distillate vs. residual oil. 

Commenters had noted that the EPA’s MACT Floor Analysis 

spreadsheet at proposal had erroneously assigned the oil type 

used during testing for some boilers. The EPA reviewed the data 

and determined that the submitting companies had entered the 

data incorrectly, or had indicated that two types of oil were 

fired in different parts of the 2010 ICR responses. The EPA 

contacted all of the companies with oil-fired EGUs in the 2010 

ICR to confirm the oil used during testing. Upon review of these 

data, it became apparent that units using residual oil with ESPs 

or distillate oil without control were the best-performing oilfired EGUs for PM and the HAP metals. Further, although 

emissions of HAP from distillate oil-fired EGUs are generally 

lower than those from residual oil-fired EGUs, EGUs burning 

distillate oil appeared to have higher emissions of some HAP but 

lower emissions of others.

In addition, the EPA does not agree that distillate oilfired EGUs were not listed in the 2000 Finding. We believe it is 

inappropriate to exclude distillate oil-fired EGUs from 

regulation under the final rule because the Agency did not make 

a distinction when listing the oil-fired units.

The EPA also disagrees with commenters that by providing 

the distillate vs. residual oil subcategories as requested, the 
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resultant standards would be more achievable. Were the EPA to 

subcategorize distillate oil from residual oil, the users of 

distillate oil would have no means of compliance other than 

obtaining “compliance” oil from their distributor (which was not 

indicated as an option by any commenter) or converting to 

natural gas and being removed from the subcategory. With no 

further subcategorization, oil-fired EGUs have the option of 

installing an ESP or converting to distillate oil for 

compliance. Commenters did not contend that it was impossible to 

convert to distillate oil, only that it would require plant 

modifications. Installing controls would also require plant 

modifications so sources will be able to evaluate the options 

and determine the most cost-effective option to comply with the 

final rule. CAA section 112 is intended to be a technologyforcing statute, and, because both distillate oil- and residual 

oil-fired EGUs were among the best performing sources in the 

floor and both types are meeting the final standards, we cannot 

reasonably conclude that the HAP emissions characteristics of 

these similar types of units are distinct. Therefore, the EPA is 

not establishing separate subcategories for distillate and 

residual oil-fired units in the final rule. 

3. Limited-use Subcategory

Comment: Several commenters stated that EPA should establish a 
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limited-use subcategory for liquid oil-fired EGUs that are 

required to burn oil during periods of natural gas curtailment. 

One commenter stated that under New York State Reliability 

Council Rules, their facility is required by the New York 

Independent System Operator (NYISO), for reliability purposes, 

to maintain the capability to burn oil and actually burn oil, 

from time to time, at varying load levels to help avoid or avert 

potential natural gas shortages in New York City. The 

requirements to burn oil under this program are mandatory and 

are not within the commenter’s discretion. The reliability rules 

require that the commenter’s EGUs maintain their co-firing 

capability to respond to unplanned, emergency scenarios by 

operating on oil during required minimum oil burn periods, 

typically 25 percent oil/75 percent natural gas. The commenter 

noted that operation using oil at other times or on 100 percent 

oil during reliability operation periods occurs very 

infrequently; with natural gas expected to become more available 

in future years, such an operating scenario will become less 

likely. However, while the reliability rules remain in place and 

commenter’s boilers are required to operate under his regimen, 

the commenter believed that it is essential that it be able to 

do so.

Other commenters noted that requiring installation of 
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emission controls on oil-fired units that operate at a 10 

percent oil-fired capacity factor or less is nonsensical and 

will result in little environmental benefit. Commenters contend 

that low-capacity factor units emit significantly less HAP than 

even well-controlled oil-fired units with much higher capacity 

factors. In addition, commenters allege that stack-testing at 

such units would be equally impractical and, in addition, would 

likely require the unit to operate on oil (and emit HAP just for 

the test) when it would otherwise be off-line or operating on 

natural gas.

Response: As stated above, after considering comments received, 

we are establishing a limited-use subcategory for liquid oilfired EGUs with an annual fired capacity factor of less than 8 

percent averaged over each 24-month block period after the 

compliance date.

At proposal, we solicited comment on establishing a 

limited-use subcategory for liquid oil-fired EGUs:

EPA is also considering 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 
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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 oil-fired 

units. EPA solicits comment on all of these proposed 

subcategorization approaches.

As stated above, the EPA did not have sufficient 

information on limited-use liquid oil-fired EGUs upon which to 

base a subcategory at proposal. Some sources required to test 

under the ICR did not submit the data until after proposal. 

Commenters indicated that their units are different because many 

of them are only called to service to address reliability issues 

associated with, for example, natural gas curtailments. The 

commenters further indicated that their units are different 

because of the generally infrequent use and the sporadic, and at 

times frequent, start-up and shutdown periods (e.g., they are 

often only required to run for a couple of hours). These factors 

would lead to differences in the emissions characteristics for 

these units such that a numeric standard based on base load 

units would not likely be achievable during the very limited 

times that these limited use oil-fired units operate. 

Based on comments received and our own analysis, we are 

finalizing a subcategory for limited-use liquid oil-fired EGUs 

as indicated elsewhere in this preamble. We find that these 
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units constitute a different class and type of units because 

they are generally only used to address reliability issues 

associated with, for example, natural gas curtailments, and 

because they in fact only run for very limited periods in a year 

on a seasonal basis.

Although some commenters indicated a prevalence of natural 

gas/oil co-fired EGUs, the EPA also understands that there are 

other liquid oil-fired EGUs that do not co-fire natural gas but 

that could be subject to mandatory operation during periods of 

natural gas curtailment in their operating area if sufficient 

non-natural gas capacity is not available. Based on a review of 

units that report oil use to EPA, in 2010 there were 228 liquid 

oil-fired EGUs with a capacity factor of less than 5 percent and 

an additional 10 units with a capacity factor of between 5 

percent and 10 percent. Only 2 of these units have capacity 

factors between 5 percent and 8 percent. This subcategory 

applies only to oil-fired EGUs that operate on oil alone and act 

as peaking units, as they generally address reliability issues.

We are establishing the capacity factor threshold of 8 percent 

averaged over each 24-month block period after the compliance 

date.321 In addition, as discussed below, we are establishing 

 

321 Units that co-fire oil and natural gas where the oil 

combustion comprises 10 percent or less of the capacity factor 

are natural gas-fired EGUs that are not subject to this final 

rule.
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work practice standard for this subcategory in lieu of numeric 

emission standards.

Commenters that requested a subcategory for these units 

noted the dichotomy of establishing a NESHAP to reduce emissions 

of HAP to the environment while at the same time requiring an 

EGU to run for the sole purpose of conducting emissions testing 

and thereby emitting those same HAP. Because the operation of 

these units is infrequent and unpredictable, performing testing 

to demonstrate that emission limits are being met requires the 

sources to be scheduled to be operated merely for the purpose of 

performing testing. We realize that similar situations occurred 

in the gathering of emissions data through the 2010 ICR. 

However, unlike the case of one-time testing on a limited number 

of these units, such testing would be mandatory on a yearly 

basis for all of the EGUs upon the effective date of the final 

rule. Because requiring testing under this rule would in many 

cases require operators of these EGUs to schedule operation of 

these EGUs at times they would not otherwise run, it would 

result in both extra cost related to the testing as well as 

extra emissions; therefore, the Agency believes that it is 

technically and economically impracticable to monitor emissions 

for these EGUs, and that they should be subject to work practice 

standards that would not require emissions monitoring.
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The annual average capacity factor would be calculated on a 

24-month block period, commencing with the compliance date of 

the final rule. For example, assuming a March 1, 2015, 

compliance date, the first 24-month block would commence on 

March 1, 2015, and end on February 28, 2017, with the next 24-

month block averaging period commencing on March 1, 2017. We 

believe the 24-month averaging period is reasonable to account 

for the fact that units needed to address reliability issues 

(e.g., natural gas curtailment periods) will be called to 

service sporadically. A 24-month averaging period provides 

flexibility to ensure that these units can run if there are 

large periods when natural gas is unavailable. As explained 

above, the data shows that most of these units operate for less 

than 8 percent of the time, and in fact it is usually less than 

5 percent. Therefore, when considering whether these units would 

be able to perform stack testing, in many cases this will be for 

units that in fact operate significantly less than 8 percent of 

the time. In these cases, the EPA does not want to require the 

units to operate more just for the purpose of running a stack 

test resulting in additional pollution and cost. With 

projections for rising oil prices relative to natural gas 

prices, we expect this trend to continue. Liquid oil-fired EGUs 

subject to this subcategory would be required to conduct the 
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same initial and periodic tune-up as all other affected units, 

but would have no other emission limit or work practice 

requirements.

Although the EPA believes that the ability to burn oil up 

to 8 percent of the time should address concerns about units 

that may need to operate using oil during gas curtailments. The 

EPA recognizes that if there were a period where gas use was 

more severely limited, such units might need the flexibility to 

operate for more than 8 percent in one year and less in the 

next, which is why we are providing the 2-year period; however 

based on the data we do not think EGUs in this subcategory will 

exceed even the 5 percent capacity factor that the data indicate 

is the average level for these sources.

4. Non-Continental Units

Comment: Commenters from affected island EGUs requested that 

non-continental EGUs be subcategorized from continental EGUs 

based on their lack of access to natural gas. The commenters 

urged the EPA to include a “non-continental liquid oil”

subcategory in the final rule. According to the commenters, 

establishing a subcategory for non-continental units is 

consistent with the approach the EPA has taken in past 

rulemakings, including the final Industrial Boiler NESHAP. Noncontinental EGUs have little or no access to natural gas, 
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minimal control over the quality of available fuel, and 

disproportionately high operational and maintenance costs. All 

oil-fired EGUs operating in Hawaii, Guam, and Puerto Rico 

combust residual fuel oil exclusively and all are limited by the 

crude slates of their fuel suppliers. Island utilities can 

contract with suppliers for certain fuel specifications, such as 

sulfur content, pour point, flash point, API gravity and 

viscosity, which the refiners are able to meet primarily by 

blending and some sulfur removal during the refining process. 

However, the commenters state that the suppliers do not and 

cannot economically control for metal content. The crude slate 

feeding the refinery determines the HAP metal content of the 

residual oil produced according to the commenters. Because 

island utilities are dependent on local sources of fuel, they 

are equally limited by these factors.

Two commenters believe that the separate non-continental 

subcategory should be expanded to include continental areas that 

are not interconnected with other utilities and have limited 

compliance options due to remote locations (e.g., Alaska).

Response: The EPA agrees that the unique considerations faced by 

non-continental EGUs warrant a separate subcategory for these 

units and the data show that the difference in location causes a 

difference in emissions apparently due to the fuel that is 
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available for such units; thus, the Agency has included such a 

subcategory in the final rule. At proposal, the EPA did not have 

all of the data from liquid oil-fired units in non-continental 

areas (e.g., Guam, Puerto Rico) and solicited comment on whether 

a subcategory should be established, based on the data to be 

received, for non-continental oil-fired EGUs. The EPA has now 

received these late data and, based on those data, is finalizing 

a non-continental subcategory for liquid oil-fired EGUs in Guam, 

Hawaii, Puerto Rico, and the U.S. Virgin Islands. The EPA is not 

aware of any liquid oil-fired EGUs in any of the other U.S. 

territories that meet the CAA section 112(a)(8) definition but, 

if there are such units, they would also be part of the noncontinental subcategory.

The EPA agrees that the unique considerations faced by noncontinental refineries, including a limited ability to obtain 

alternative fuels that lead to different emissions 

characteristics, warrant a separate subcategory for these EGUs.

The EPA believes that units in this subcategory will comply 

through the use of cleaner oils or, for PM, through the 

installation of an ESP. The EPA finds no merit in the comment 

that Alaska should be included in this non-continental 

subcategory because utilities in Alaska are not faced with the 

same access issues affecting island-based facilities.
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C. Surrogacy

1. Filterable PM vs. Total PM

Comment: Numerous commenters strongly objected to the use of 

total PM as the surrogate standard for non-mercury HAP metals. 

They argued that filterable PM is a better surrogate, especially 

given EPA’s intent to use a PM CEMS for continuous compliance 

demonstration. Other commenters argued that we should not use a 

surrogate and instead should require direct compliance with a 

non-mercury HAP metals standard.

Response: We have decided to use a filterable PM limit for the 

PM surrogate emission limit in the final rule.

Although the objective of the emission limits we are 

establishing is to reduce the risks associated with HAP 

emissions, the limits are based in part upon the demonstrated 

capabilities of control technologies which are installed on 

existing sources. Except for Hg, the best PM controls provide 

the best controls of metal emissions. Emissions measurements of 

either filterable particulate, total particulate, individual 

metals, or total metals provide comparable indications that the 

best level of control is achieved. We can find no significant 

difference in the emissions that would be achieved by using any 

one of these emissions measurements.

We re-assessed the relationships between individual metal 
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emissions, filterable PM emissions, total PM emissions, and 

total PM2.5 emissions based on the test results provided through 

Part III of the 2010 ICR. We compared the measured emissions of 

metals and PM with the uncontrolled emissions estimates and 

found that control of PM was indicative of the control of metals 

emissions. In addition, we compared the correlations associated 

with non-mercury HAP metal emissions and the three forms of PM 

and found that no specific particulate form provided a 

consistently superior indicator of better metals control. 

Although control of filterable PM provided the best indicator of 

performance for control of some HAP metals, control of total 

particulate or total PM2.5 was nearly as good as an indicator. 

For control of other HAP metals, total PM measurement provided 

the best indicator of control performance because it included 

the vapor-phase metal HAP, although, measurement of the control 

of filterable particulate was nearly as good an indicator. In 

addition, certain data analyzed by our Office of Research and 

Development indicate that a vapor-phase metal, such as Se, can 

be present as an acid gas and reduced significantly using acid 

gas technologies (wet and dry scrubbing). Given that the rule 

also provides for acid gas control monitoring, and the general 

equivalency of the different indicators, we have concluded that 

use of a filterable PM limit as the PM surrogate emission limit 
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is appropriate.

2. Moisture Content of Oil

Comment: A number of commenters stated that studies suggest that 

chloride in fuel oil can result from contamination during 

transportation and processing of crude oils and then be emitted 

as HCl during combustion. For example, the commenters asserted 

that the chloride contamination of crude oils can occur as a 

result of the ballasting of tanker ships with seawater. However, 

the Oil Pollution Act of 1990 requires all new oil tankers to be 

double hulled and establishes a phase out schedule (by the 

middle of the decade) for existing single hulled tankers with 

un-segregated ballasts. Because of the role of seawater 

contamination in introducing contaminants into the oil, the 

commenters suggest that the EPA set a percent water content 

limit for fuel oil at a level of 1.0 percent, rather than 

setting HCl and HF emissions limits. This would encourage 

handling and transport practices to limit salt water 

contamination. One commenter recommended a standard of 1.0 

percent water because several of the lowest HCl and HF emitting 

units currently require percent water (or water and sediment) 

specifications between 0.5 percent and 1.0 percent.

Response: The EPA is providing the alternative compliance 

assurance approaches in the final rule for liquid oil-fired EGUs 
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of demonstrating compliance through either specific HCl or HF 

measurements or by demonstrating that the moisture content in 

the fuel oil remains at a level no more than 1.0 percent.

The EPA is not aware of any FGD systems installed on oilfired EGUs. Thus, it is only the quality of the oil, and the 

level of HAP constituents contained therein, that can be relied 

upon for ensuring compliance.

In the proposal preamble, we stated:

We believe that chlorine may not be a compound 

generally expected to be present in oil. The ICR data 

that we have received suggests that in at least some 

oil, it is in fact present. EPA requests comment on 

whether chlorine would be expected to be a contaminant 

in oil and if not, why it is appearing in the ICR 

data. To the extent it would not be expected, we are 

taking comment on the appropriateness of an HCl limit.

See 76 FR 25045.

Commenters refer to certain studies that provide a

plausible reason for the chloride/fluoride contamination of fuel

oils. We found this reason persuasive and accordingly are 

providing alternative compliance approaches in the final rule to 

demonstrate compliance with the acid gas HAP standards. 

Specifically, sources can demonstrate compliance through either 
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specific HCl or HF measurements or by demonstrating that the 

moisture content in the fuel oil remains at a level no more than 

1.0 percent.

D. Area Sources

Comment: Numerous comments were received both in support of and 

in opposition to the establishment of generally available 

control technology (GACT) standards for area source EGUs.

Several commenters in opposition to area source standards 

stated that the EPA properly established emissions limitations 

based upon the performance of all EGUs, rather than 

distinguishing between major sources and area sources. The 

commenters believe that Congress did not intend the EPA to 

distinguish between “major source” EGUs and “area source” EGUs 

in determining whether and how to regulate EGUs under CAA 

section 112. These commenters indicated that differentiating 

major source and area source EGUs for purposes of setting 

emissions standards is inappropriate in light of the 2000 

Finding regarding the threat posed by the absence of regulation 

of HAP emissions from EGUs. The 2000 Finding was based upon 

studies whose conclusions regarding the impacts from EGU 

emissions did not depend upon any relevant distinction between 

major source and area source EGUs. The commenters note that 

segregating “major source” and “area source” EGUs would have the 
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perverse effect of eliminating some of the best performing 

sources from the MACT pool of sources that constitute the “best 

performing” 12 percent. Many of the best performing sources have 

employed control technology that brings their emissions below 

the major source threshold, despite the fact that they are 

larger units. As a result, the commenters believe that if the 

EPA created standards for “major source” EGUs based only upon 

those units, the MACT standards for “major source” EGUs would be 

less stringent for each of the pollutants than proposed in this 

Rule. At the same time, the less polluting sources, the “area 

source” EGUs, could face limits more stringent than those 

proposed in the Rule. Commenters also note that after reviewing 

the substantial record in this rulemaking, they believe that the 

EPA has correctly determined that major and area source EGUs 

greater than 25 MW have similar HAP emissions and use the same 

control technologies and techniques to reduce HAP emissions. 

Thus, the commenters asserted that the record demonstrates that 

there is no technical basis for distinguishing between major and 

area source EGUs for purposes of establishing HAP emission 

control standards under CAA section 112(d).

Many commenters in support of an area source designation 

for EGUs stated that the EPA has promulgated area source limits 

for many source categories of HAP emissions, including most 
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recently industrial boilers and note that GACT controls have 

been used successfully in many other EPA MACT rules, including 

rules for iron & steel foundries, electric arc steelmaking, 

coatings operations, clay ceramics manufacturing, glass 

manufacturing, and secondary nonferrous metals manufacturing, in 

order to reduce costs and regulatory burdens. The commenters 

state that Congress has given the EPA the ability to 

subcategorize area sources because of their low HAP emissions 

and low potential impact on human health and that, contrary to 

the plain language of CAA section 112 and its legislative 

history, the EPA made no attempt in the proposed rule to 

distinguish between major sources and area sources for purposes 

of listing or setting standards. The commenters indicated that 

where Congress was concerned about the health impacts of 

specific pollutants from specific sources, it knew how to 

specify that MACT limits be promulgated (e.g., CAA section 

112(c)(6)). The commenters state that area source rules would 

lessen the regulatory burden of a CAA section 112 EGU rule on 

many small entities (arguing that many EGUs owned by small 

public power entities are area sources) and that as many as 12 

percent of the EGU population could qualify as area sources. A 

number of commenters pointed out that the small entity 

representatives (SER) on the SBREFA panel suggested that the EPA
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establish separate emission standards for EGUs located at area 

sources of HAP and that the standards be based on GACT as 

allowed under CAA section 112(d)(5). Specifically, the SERs 

recommended that the EPA establish management practice standards 

for area source EGUs.

Response: The EPA is not establishing an area vs. major source 

distinction in the final rule.

The CAA section 112(a)(8) definition of EGU does not 

distinguish between major and area sources, and we maintain that 

EGUs are a single source category that contains both major and 

area sources. The EPA proposed to regulate five subcategories of 

EGUs without distinguishing between major and area sources for 

purposes of establishing the standards for the different 

subcategories. Our approach is wholly consistent with the 

statutory definition of EGU and reasonable.

Nevertheless, the Agency did examine whether to set 

separate standards for area source EGUs, because we do not

believe that the statute prohibits the Agency from exercising 

its discretion to establish GACT standards for area sources 

pursuant to CAA section 112(d)(5) if we determine such standards 

are appropriate. The EPA is not required, however, to establish 

GACT standards for area sources, and we believe it may even be 

unreasonable to do so under the circumstances we identified in 
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the proposed rule as supported by the record of this final rule. 

At proposal, we determined that it was not appropriate to 

establish separate standards for major and area source EGUs, and

even if we had exercised our discretion to set separate 

standards, we would have likely declined to exercise our 

discretion to set GACT standards for area source EGUs given our 

appropriate and necessary finding and the fact that a 

potentially large number of area source EGUs are in fact large 

well controlled units.

Some commenters note that there could be as many as 12 

percent of the total population that could be classified as area 

sources. We are not sure of the commenters’ point in regard to 

this statement. As to commenters’ statements that many of the 

area sources are municipal utilities, our information shows that 

many rather large EGUs (e.g., hundreds of MW) are also area 

sources, and the commenters have not provided any justification 

for establishing GACT standards for large synthetic area 

sources.

Commenters did not provide an evaluation of the health and 

environmental impacts of the area sources and simply presume

that the risks from such sources are lower, even though many of 

the same commenters noted that these smaller EGUs are often 

located in densely populated areas where populations are more 
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likely to have adverse health effects from the HAP emissions.

Furthermore, other commenters, including some industry 

commenters, noted that the vast majority of these potential area 

sources meet the criteria due to the installation of emission 

controls installed to meet other requirements. According to 

these commenters, these synthetic area sources would likely be 

able to meet the limits of this rulemaking and imposition of 

this rule would not appear to result in the installation of 

additional controls in a number of cases. We do not know if this 

assertion is correct but we determined approximately 69 coalfired EGUs will be able to meet the existing source MACT 

standards with their current control configuration (out of 252 

EGUs that reported data for Hg, PM, and HCl in the 2010 ICR).

Commenters also note that the Agency has exercised its 

discretion in other NESHAP rulemakings to establish area source 

limits. Although true, the fact that the EPA has established 

area source limits in some source categories is irrelevant to 

similar decisions for different source categories. Commenters 

have not shown that the circumstances applicable to those other 

source categories are similar to the circumstances identified 

for major and area source EGUs (e.g., similar controls, similar 

emission characteristics, large number of synthetic minor area 

sources). Further, those other source categories are not 
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statutorily defined in a manner that includes both area and 

major sources. EGUs are the only source category defined in CAA 

section 112 and, in establishing the definition of an “electric 

utility steam generating unit” under CAA section 112(a)(8), 

Congress included in the EGU source category both area and major 

sources. Thus, it is reasonable to regulate the EGU category in 

the manner Congress defined the category. Commenters have 

provided no legal support for the contention that the EPA must 

regulate area and major sources in the same category in separate 

rulemakings, and the EPA has in fact regulated both major and 

area sources in the same rulemaking even absent a statutory 

definition that includes both major and area sources. (See

National Emission Standards for Hazardous Air Pollutants From 

the Portland Cement Manufacturing Industry and Standards of 

Performance for Portland Cement Plants; 75 FR 54970; September 

9, 2010.)

The EPA considered the totality of the circumstances when 

determining whether to set separate area and major source 

standards for EGUs and also considered whether it would be 

reasonable to establish GACT standards for areas sources. We 

reasonably considered whether emissions characteristics of major 

and area sources are different when determining whether to 

establish GACT standards, notwithstanding commenters’ assertion 
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that such consideration is not correct. That we also consider 

emission characteristics in subcategorization decisions is of no 

consequence for area source decisions. Given that the statutory 

definition of EGUs contains both major and area sources, it was 

reasonable to evaluate whether there were sufficient differences 

between area and major sources when deciding whether to exercise 

our discretion to set separate area and major source standards.

In addition, we find commenter’s point concerning CAA 

section 112(c)(6) odd because EGUs emit several of the CAA 

section 112(c)(6) HAP (e.g., lead, Hg). Although EGUs were 

exempted from that provision, the fact that they emit some of 

the HAP called out for MACT control supports our decision to not 

establish GACT standards for any EGUs. CAA section 112(d)(5) 

leaves it to the Agency’s discretion to determine whether GACT 

standards should be established for area sources, and the 

statute does not require GACT standards or even indicate that 

such standards are to be the default regulatory approach for 

area sources. See 76 FR 25021. Instead, the statute provides the 

Agency with discretion and we have exercised it reasonably in 

this case.

Commenters indicate that many EGUs owned by small entities 

are potential area sources. However, commenters fail to note 

that there are also EGUs owned by small entities that are not
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potential area sources, and, thus, would not accrue any 

“lessened regulatory burden” benefit from a decision by the EPA 

to establish area source standards.

Some commenters state that the EPA’s mere assertion that 

there would be no difference between GACT and MACT to justify an 

area source finding does not provide sufficient documentation 

for the decision. But EPA did not say there would be no 

difference between MACT and GACT. Instead, it stated that it 

would be difficult to make a distinction given the similarities 

between the EGUs and major and area source facilities. 

Specifically, as noted by other commenters, and observable by a 

review of the MACT Floor Analysis spreadsheets, potential area 

sources range in size from units near the CAA section 112(a)(8) 

defined lower size limit to units of hundreds of megawatts. 

Further, these larger area source units are, for the most part, 

controlled with the full suite of emission control technologies 

available (e.g., fabric filters, scrubbers). 

In addition, the data that were available in the docket for 

the proposed rule show that there is little difference between 

major and area source EGUs individually, and that generally the 

driver for whether a utility facility is a major or area source 

depends on the number of EGUs located at a facility (almost 

exclusively one or two EGUs located at area sources), not on any 
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inherent difference between the EGUs themselves. See “Evaluation 

of Area Source EGUs” TSD, Docket EPA-HQ-OAR-2009-0234. In fact 

there are a number of EGUs that are quite large that are area 

sources and others that are small that are major sources. Id. 

This is the case because the acid gas HAP emissions are what 

drive EGUs to have HAP emissions exceeding the major source 

threshold. With a few exceptions, the EGUs located at area 

sources have FGD or other acid gas controls that reduce the acid 

gas HAP to area source levels. Id. Thus, the majority of sources 

that currently qualify as area sources were, in fact, major 

sources prior to installing controls. The exceptions are those 

units that would likely be able to achieve the MACT level of 

control for acid gas with minimal use of DSI at a reasonable 

cost. Id. 

In addition, the data show that a number of area sources 

for which we have data are high emitters of Hg and non-Hg metal 

HAP. Id. Pursuant to our appropriate and necessary finding, 

these HAP pose a significant threat to human health. Thus, even 

were we to distinguish between major and area sources, which we 

do not believe is appropriate given the similarities between 

such sources, we would still decline to set GACT standards, and 

as such we maintain that MACT standards are appropriate. 

Moreover, for acid gas HAP, as discussed above, the data 
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indicate that the level of control would likely be the same even 

if we did establish GACT standards under CAA section 112(d)(5). 

We fully evaluated the nature of EGUs, and we do not see a 

basis on which to distinguish these sources for purposes of 

setting standards. Thus, we maintain that we reasonably 

exercised the discretion afforded the Agency under the statute 

and declined to set separate standards for area source EGUs.

E. Health-based Emission Limits

Comment: Many commenters noted that in the proposed rule the EPA

considered whether it was appropriate to exercise its 

discretionary authority to establish health-based emission 

limits (HBEL) under CAA section 112(d)(4) for HCl and other acid 

gases and proposed not to adopt such limits, citing, among other 

things, information gaps regarding facility-specific emissions 

of acid gases, co-located sources of acid gases and their 

cumulative impacts, potential environmental impacts of acid 

gases, and the significant co-benefits estimated from the 

adoption of the conventional MACT standard. Comments were 

received both supporting this position and refuting it. Several 

commenters suggested legal, regulatory and scientific reasons 

for why HBEL for HCl might be appropriate for this MACT 

standard. With respect to legal concerns, some commenters 

indicated that CAA section 112(d)(4) establishes a mechanism for 
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the EPA to exclude facilities from certain pollution control 

regulations and circumstances when these facilities can 

demonstrate that emissions do not pose a health risk. Commenters 

cited a Senate Report that influenced development of CAA section 

112(d)(4), where Congress recognized that, “For some pollutants 

a MACT emissions limitation may be far more stringent than is 

necessary to protect public health and the environment.”

(Footnote: S. Rep. No. 101-128 (1990) at 171.) Commenters also 

cited regulatory precedent for addressing HCl as a threshold 

pollutant, including the Hazardous Waste Combustors and the 

Chemical Recovery Combustion Sources at Kraft, Soda, Sulfite, 

and Stand-Alone Semichemical Pulp Mills NESHAP. Commenters 

requested that the EPA incorporate the flexibility afforded by 

CAA section 112(d)(4) and allow sources reasonable means for 

demonstrating that their respective emissions do not warrant 

further control. The commenters also cited the 2004 vacated 

Boiler MACT as precedent for HBEL for HCl. The commenters 

contended that the EPA failed to explain why the health-based 

emissions limitations it established in the 2004 Boiler MACT and 

the justification provided for those limitations could not be 

used in this case. The commenters also cited a 2006 court 

briefing where the EPA vigorously defended the HBEL included in 

the 2004 Boiler rule when it was challenged in the D.C. Circuit 
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(Final Brief For Respondent U.S. Environmental Protection 

Agency, D.C. Cir. Case No. 04-1385 (Dec. 4, 2006) at 59-65, 69).

Other commenters stated that on August 6, 2010, the EPA

adopted a NESHAP for Portland Cement plants that specifically 

rejected adoption of risk-based exemptions or HBEL for HCl and 

manganese (Mn). These commenters argue there are no differences 

sufficient to warrant a reversal of that decision in the EGU 

MACT standard. The commenters raised concerns that health risk 

information cited by the EPA for HCl, HF, and hydrogen cyanide 

(HCN) does not establish “an ample margin of safety” and, 

therefore, no health threshold should be established. The 

commenters believe risk-based exemptions at levels less 

stringent than the MACT floor are prone to lawsuits that could 

potentially further delay implementation of the EGU MACT.

Some commenters disagreed with using a hazard quotient (HQ) 

approach to establish a risk-based standard because the HQ would 

not account for potential toxicological interactions. The 

commenter noted that an HQ approach incorrectly assumes the 

different acid gases affect health through the same health 

endpoint, rather than assuming that the gases interact in an 

additive fashion. This commenter suggested that a hazard index 

approach, as described in the EPA’s “Guideline for the Health 

Risk Assessment of Chemical Mixtures,” would be more 
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appropriate.

Some commenters dispute that emissions from other EGUs or 

source categories should be considered when developing an HBEL 

and they argued that Congress expected the EPA to consider the 

effect of co-located facilities during the CAA section 112(f) 

residual risk program instead of under CAA section 112(d). 

Commenters added that there is no prior EPA precedent for 

considering co-located facilities from a different source 

category during the same CAA section 112 rulemaking.

Several commenters disputed the EPA’s consideration of nonHAP collateral emissions reductions in setting MACT standards. 

They contended that the EPA’s sole support for its “collateral 

benefits” theory is legislative history – the Senate Report that 

accompanied Senate Bill 1630 in 1989 and noted that the D.C. 

Circuit rejected this use of this theory since the Senate Report 

referred to an earlier version of the statute that was 

ultimately not enacted. Instead commenters suggested that other 

components of the CAA, such as the National Ambient Air Quality 

Standards (NAAQS), are more appropriate avenues for mitigating 

emissions of criteria pollutants. 

Several other commenters suggested it is impossible to 

assess an established health threshold for HCl such that a CAA 

section 112(d)(4) standard could be set without evaluating the 
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collateral benefits of a MACT standard. And, as described in the 

recently finalized cement kiln MACT rule, setting technologybased standards for HCl will result in significant reductions in 

the emissions of other pollutants, including SO2, Hg, and PM. The 

commenter added that these reductions will provide enormous 

health and environmental benefits, which would not be 

experienced if CAA section 112(d)(4) standards had been 

finalized. These commenters contended that HCl and other 

dangerous acid gases produced by EGUs pose substantial risks to 

industrial workers, as well as surrounding communities, and must 

be limited by the strict conventional MACT standards.

Several commenters indicated that the current economic 

climate requires the EPA to balance economic and environmental 

interests and indicated that HBEL would help target investments 

into solving true health threats where limits are no more or 

less stringent than needed to protect public health. Many 

commenters provided estimates of compliance cost savings if an 

HBEL is included in this final rule. Some commenters stressed 

the importance of an HBEL for small entities affected by the 

regulations. Several other commenters suggested that the EPA

should estimate the costs and environmental effects of the HBEL 

option compared to a conventional MACT standard in order to make 

an informed decision on the adoption of HBEL.
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Response: After considering the comments received, the EPA has 

decided not to adopt an emissions standard based on its 

authority under CAA section 112(d)(4) for all the reasons set 

forth in the proposed rule. 

The EPA notes that the Agency’s authority under CAA section 

112(d)(4) is discretionary. That provision states that the EPA

“may” consider establishing health thresholds when setting 

emissions standards under CAA section 112(d). By the use of the 

term “may,” Congress clearly intended to allow the EPA to decide 

not to consider a health threshold even for pollutants which 

have an established threshold. As explained in the preamble to 

the proposed rule, it is appropriate for the EPA to consider 

relevant factors when deciding whether to exercise its 

discretion under CAA section 112(d)(4), and, notwithstanding 

commenters’ assertions to the contrary, the considerations we 

include in our analysis are reasonable. The EPA has considered 

the public comments received and is not adopting an emissions 

standard under CAA section 112(d)(4) for the reasons set forth 

in the proposed rule and explained below. We note that this 

action is consistent with EPA’s recent decisions not to develop 

standards under CAA section 112(d)(4) for the Industrial, 

Commercial and Institutional Boilers and Process Heaters and the 

Portland Cement source categories.
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As explained in the preamble to the proposed rule, the EPA 

continues to believe that the potential cumulative public health 

and environmental effects of all acid gas HAP emissions, not 

just HCl emissions, from EGUs and other acid gas sources located 

near EGUs supports the Agency’s decision not to exercise its 

discretion under CAA section 112(d)(4). Additional data for all 

acid gas emissions were not provided during the comment period, 

and the data already in hand regarding these emissions are not 

sufficient to support the development of emissions standards for 

EGUs under CAA section 112(d) that take into account the health 

threshold for acid gas HAP, particularly given that the Act 

requires the EPA’s consideration of health thresholds under CAA 

section 112(d)(4) to protect public health with an ample margin 

of safety. We note here that EPA agrees with the commenter who 

pointed out that a better way to evaluate the potential health 

impact interactions of all acid gases would be to use the 

approach in EPA’s “Guideline for the Health Risk Assessment of 

Chemical Mixtures” rather than a simple evaluation of individual 

HQ values for each acid gas, but we further note that use of 

such an approach requires a substantially greater knowledge of 

acid gas emissions than is currently available. We further note 

that, even if cost were a relevant factor in setting standards 

under CAA section 112(d)(4), since the data are not available 
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that would allow us to develop an acid gas HBEL appropriate to 

protect public health with an ample margin of safety, we cannot 

determine whether such standards would have any cost savings 

associated with them or not. In addition, the concerns expressed 

by the EPA in the proposal regarding the potential environmental 

impacts and the cumulative impacts of acid gases on public 

health were not assuaged by the comments received because no 

significant data regarding these impacts were received. 

The EPA also received comments recommending not only that 

the EPA establish emissions standards for acid gases pursuant to 

CAA section 112(d)(4), but that it do so by excluding specific 

facilities from complying with emissions limits if the facility 

demonstrates that its emissions do not pose a health risk. The 

EPA does not believe that a plain reading of the statute 

supports the establishment of such an approach. Although CAA 

section 112(d)(4) authorizes the EPA to consider the level of 

the health threshold for pollutants which have an established 

threshold, that threshold may be considered “when establishing 

emissions standards under [CAA section 112(d)].” Therefore, the 

EPA must still establish emissions standards under CAA section 

112(d) even if it chooses to exercise its discretion to consider 

an established health threshold. A source-by-source standard is 

not mandated as some commenters seem to imply, and we are unsure 
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how we could reasonably implement such an approach even if we 

determined such an approach was legally available. For these 

reasons alone, we concluded it was not appropriate to exercise 

our discretion to establish section 112(d)(4) standards for acid 

gas HAP emissions.

In addition, as explained in the preamble to the proposed 

rule, the EPA also considered the co-benefits of setting a 

conventional MACT standard for HCl. The EPA considered the 

comments received on this issue and continues to believe that 

the estimated co-benefits are significant and provide an 

additional basis for the Administrator to conclude that it is 

not appropriate to exercise her discretion under CAA section 

112(d)(4). The EPA disagrees with the commenters who stated that 

it is not appropriate to consider non-HAP benefits in deciding 

whether to invoke CAA section 112(d)(4). Although MACT standards 

may directly regulate only HAP and not criteria pollutants, 

Congress did recognize, in the legislative history to CAA 

section 112(d)(4), that MACT standards would have the collateral 

benefit of controlling criteria pollutants as well and viewed 

this as an important benefit of the air toxics program. See S. 

Rep. No. 101-228, 101st Cong. 1st sess. at 172. The EPA 

consequently does not accept the argument that it cannot 

consider reductions of criteria pollutants in determining 
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whether to take or not take certain discretionary actions, such 

as whether to adopt an HBEL under CAA section 112(d)(4). There 

appears to be no valid reason that, in situations where the EPA

has discretion in what type of standard to adopt, the EPA must 

ignore controls which further the health and environmental 

outcomes at which CAA section 112(d) is fundamentally aimed 

because such controls not only reduce HAP emissions but 

emissions of other air pollutants as well. Thus, the issue being 

addressed is not whether to regulate non-HAP under CAA section 

112(d) or whether to consider other air quality benefits in 

setting CAA section 112(d)(2) standards – neither of which the 

EPA is doing – but rather whether EPA may exercise its 

discretion to regulate certain HAP based on the MACT approach 

and consider collateral health and environmental benefits when 

choosing whether to exercise that discretion. The EPA believes 

there is no legal principle that precludes it from doing so and 

commenters have not provided one.

F. Compliance Date and Reliability Issues

Comment: Multiple commenters asked that the compliance date be 

clearly stated as soon as possible, as well as that guidance be 

provided for utilities unable to comply with the stated 

timelines, to allow time for utilities to prepare for 

compliance. Commenters also asked that any decisions or policies 
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on extensions be published in a rulemaking. In addition, 

commenters requested that the EPA establish, streamline, and 

simplify the process of applying for the 1-year extension under 

CAA section 112(i)(3).

Multiple commenters offered suggestions on methods for 

allowing more time for compliance, including EPA’s authority 

under CAA section 112(n)(1)(A); state authority under CAA 

section 112(i)(3); Presidential authority under CAA section 

112(i)(4); categorical extensions for publicly-owned or 

governmental facilities according to EO 13132, 13563, and UMRA

of 1995; state-designed programs under the delegation provisions 

of CAA section 112; various Consent Decrees; Administrative 

Orders of Consent (AOCs); temporary waiver mechanisms; and 

adoption of MACT compliance schedules through minor permit 

modifications of a source’s Title V federal operating permits. 

Absent such considerations for additional compliance time, many 

commenters suggested that the reliability of the nation’s 

electric grid would be jeopardized as utility companies were 

forced to retire EGUs because they could not install the needed 

controls in the requisite time.

Compliance times requested by commenters ranged from 1 

additional year (4 years total) to 6 additional years (9 years 

total). Multiple commenters requested that a utility be required 
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to demonstrate good faith progress toward compliance to get any 

extension. Some commenters suggested that the EPA require 

utilities to submit a notice concerning which EGUs will be 

retrofitted or retired within 1 year of the effective date; that 

the compliance date align with the Power Year used by RTOs; and 

that the EPA clarify that retirement and any clean replacement 

power that complies with the NESHAP rule, including off-site 

combined heat and power and waste heat recovery, can be deemed 

“controls” under the CAA.

Commenters noted the specific situations related to small 

entities and their inability to compete with the larger, 

investor-owned utilities for financing and engineering and 

technical labor as well as the different process they need to 

follow for capital improvements. Multiple commenters asked that 

the EPA consider other simultaneous rulemakings (e.g., Cooling 

Water Intake Structures; Coal Combustion Residuals; CSAPR, etc.) 

and extend the compliance period. Many commenters noted these 

other requirements and suggested that installation of the 

necessary controls could not be completed within the compliance 

period allowed under CAA section 112, even if a fourth year were 

to be granted by the permitting authority, citing examples of 

the times necessary for installation of various pieces of 

control equipment or replacement power.
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Some commenters pointed to existing state programs (e.g., 

Colorado, Oregon, Washington) and indicated that if states can 

demonstrate that overall emissions reductions would be 

equivalent or greater than those that would be achieved by the 

proposed rule, the EPA should delegate the CAA section 112 

program to these states, even if the state emissions reductions 

would not necessarily occur on the same schedule (many state 

programs call for retirement of EGUs in years beyond the CAA 

section 112 compliance date). The commenters did not want the 

promulgation of the final rule to undermine the significant 

amount of work that may have been invested in creating statespecific programs to curb emissions within a reasonable 

timeframe. The commenters seek to make use of temporal 

flexibility, authorized under CAA section 112(i)(3), in 

obtaining delegation of the final rule to preserve the hardnegotiated comprehensive state-specific programs designed to 

yield greater emission reductions than the MATS alone.

Other commenters requested that no additional time be 

granted for compliance. These commenters reference a number of 

reports (e.g., by the URS Corporation, by M.J. Bradley & 

Associates and the Analysis Group, and by the Bipartisan Policy 

Center) to indicate that not only is technology readily 

available, but that the technology can typically be installed in 
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less than 2 years and that the electric industry is wellpositioned to comply with the EPA’s proposed air regulations 

without threatening electric system reliability. Commenters 

assert that, if electric system reliability were to be 

threatened in local areas as a result of the rule, the EPA has 

the statutory authority to grant, on a case-by-case basis, 

extensions of time to complete the installation of pollution 

control systems. One commenter stated that no additional 

controls would need to be installed in many cases and any coal 

unit should be able to comply with all of the standards. Another 

commenter noted that utilities that failed to plan ahead “should 

not be permitted to use their own inaction to justify more 

time.” Commenters noted that several major utility companies 

have anticipated the EPA’s rules and are already taking action 

to ensure a reliable supply of electricity in their service 

territory and beyond. Other commenters agree that there is 

significant excess generation capacity in the country and 

reliability will not be threatened by the rule. According to one

commenter, companies are already preparing for a 2015 compliance 

date, factoring in the capital expenditures required to comply 

and delays would undermine decisions that have already been 

made. Commenters cite, for example, recent electricity forward 

capacity market auctions in the PJM market for the period of 
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2014 and 2015 that indicate that the capacity markets cleared 

with electricity reserve margins of 20 percent; this is in 

excess of the default reliability targets used by the North 

American Electric Reliability Corporation (NERC) for the year 

2015. One commenter quoted NERC, stating that NERC does not see 

impacts from proposed climate legislation or anticipated EPA 

regulation as a reliability concern. Another commenter noted 

that the Building and Construction Division of the AFL-CIO has 

stated that there is no evidence to suggest that the 

availability of skilled manpower will constrain pollution 

control technology installation. In fact, according to the 

commenter, given the high levels of unemployment in the 

construction sector, these jobs are much needed.

A number of commenters expressed concern that the time 

frame for compliance with a regulation under CAA section 112(d) 

was too short for this industry and would result in compromising 

the reliability of electricity supply. Commenters asserted that 

reliability would be compromised in several ways: (1) EGUs might 

have to temporarily close if the owner or operator is unable to 

install controls on the unit within the 3-year time frame or 3 

years plus one; (2) the timing of outages to install controls 

will cause short term closures that could threaten grid 

stability; (3) owner/operators may shut down EGUs rather than 
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invest in retrofits to keep them running and that these closures 

may cause a loss of critical generation; and (4) the 

construction of replacement generation or implementation of 

other measures to address reliability concerns due to plant 

retirements could take longer than 3 years, and that units 

slated for closure may be necessary beyond the 3-year compliance 

period but will be unable to run because they have not installed 

the necessary controls.

Response: Clean Air Act section 112 specifies the dates by which 

affected sources must comply with this rule. New or 

reconstructed units must be in compliance immediately upon 

startup or the effective date of this rule, whichever is later. 

Existing sources may be provided up to 3 years after the 

effective date to comply with the final rule; if an existing 

source is unable to comply within 3 years, a permitting 

authority has the ability to grant such a source up to a 1-year 

extension, on a case-by-case basis, if such additional time is 

necessary for the installation of controls. 

As is explained earlier in this preamble, the 3-year 

compliance window is based on the date that is 60 days after 

publication of this rule in the Federal Register. Because 

publication doesn’t occur until several weeks after the rule is 

signed by the Administrator, the earliest required date for 
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compliance would be sometime in March 2015. Because the last 

stage of control installations usually needs to occur when the 

unit is off-line and because scheduled outages are usually 

scheduled for the spring or fall months when peak electric 

demand is lower, this additional time is significant as it 

provides companies an additional outage period, the spring of 

2015, to install controls.

The EPA has considered the concerns raised by commenters 

and has concluded that given the flexibilities further detailed 

in this section, the requirements of the final rule for existing 

sources can be met by most sources without adversely impacting 

electric reliability. In particular, EPA believes that the 

flexibility of permitting authorities to allow a fourth year for 

compliance should be available in a broad range of situations 

(as discussed below), and that this flexibility addresses many 

of the concerns that have been raised. Furthermore as indicated 

below, in the event that an isolated, localized concern were to 

emerge that could not be addressed solely through the 1-year 

extension under CAA section 112(i)(3), the CAA provides 

flexibilities to bring sources into compliance while maintaining 

reliability.

The EPA considered the impact that potential retirements in 

response to this rule will have on resource adequacy in order to 
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gauge the rule’s impact on reliability. In considering these 

impacts, the EPA considered both the analysis it has conducted 

as well as analyses conducted by a number of other groups. The 

EPA’s analysis shows that the expected retirements of coalfueled units as a result of this final rule (4.7 GW) are fewer 

than was estimated at proposal and much fewer than some have 

predicted.322 The net capacity reductions projected by the EPA 

make up less than one-half of one percent of the total 

generating capacity in the U.S. and about one and one-half 

percent of U.S. coal capacity. Because concerns have been raised 

that the use of DSI may not be as prevalent as the Agency has 

predicted and because this could lead to more coal retirements, 

the Agency also performed a sensitivity analysis in which fewer

DSI systems and more scrubber systems were installed. In that 

sensitivity, we see approximately 1 more GW of retirements. This 

small change would have only a very small potential impact on 

resource adequacy. When considering the impact that one specific 

action has on power plant retirements, it is important to 

understand that the economics that drive retirements are based 

on multiple factors including: expected demand for electricity, 

 

322 The EPA’s analysis also identifies a small amount of capacity 

loss (less than 0.7 GW) due to derating of certain units, as 

well as partially offsetting reductions in non-coal retirements 

in comparison with the base case. The net estimated reduction in 

capacity, in comparison with the base case, is estimated at less 

than 5 GW.
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the cost of alternative generation, and the cost of continuing 

to generate using an existing unit. The EPA’s analysis shows 

that the lower cost of alternative fuels, particularly natural 

gas, as well as reductions in demand, will have a greater impact 

on the number of projected retirements than will the impact of 

this final rule.

The EPA’s assessment looked at the capacity reserve margins 

in each of 32 subregions in the continental U.S. Demand 

forecasts used were based on EIA projected demand growth. The 

analysis shows that with the addition of very little new 

capacity, average reserve margins are significantly higher than 

required. The NERC assumes a default reserve margin of 15 

percent while the average capacity margin seen after 

implementation of the policy is nearly 25 percent. Although such 

an analysis does not address the potential for more localized 

reliability concerns associated with transmission constraints or 

the provision of location-specific ancillary services (such as 

voltage support and black start service), the number of 

retirements projected suggests that the magnitude of any local 

reliability concerns should be manageable with existing tools 

and processes.

Several outside analyses have reached conclusions 

consistent with EPA’s analysis. The DOE, in December 2011,
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published a report that looked at resource adequacy in the bulk 

power system when faced with a stress test which was a 

regulatory scenario far more stringent than EPA’s regulations.323

For this stress test, in addition to CSAPR and MATS 

requirements, each uncontrolled electric generator is required 

to install both a wet FGD system and a fabric filter to reduce 

air toxics emissions. If such installations are not economically 

justified, this scenario assumes that the plant must retire by 

2015. In reality, as discussed previously, power plant owners 

will have multiple other technology options to comply with the 

regulations – options that typically cost less than 

installations of FGDs and fabric filters. The analysis finds 

that target reserve margins can be met in all regions, even 

under these stringent assumptions. Moreover, in every region but 

one (TRE), no additional new capacity is needed. In TRE, the 

analysis finds that less than 1 GW of new natural gas capacity 

would be needed by 2015 beyond the additions already projected 

to occur in the Reference Case. This analysis also finds that 

the total amount of new capacity that would be added by 2015 is 

less than the amount that is already under development.

In June 2011, the Bipartisan Policy Center issued a report 

analyzing potential collective impacts of EPA’s pending power 

 

323 U.S. Department of Energy, December 2011, “Resource Adequacy 

Implications of Forthcoming EPA Air Quality Regulations”.
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sector rules and concluding that “scenarios in which electric 

system reliability is broadly affected are unlikely to occur.”324

In August 2011, PJM Interconnection – the Regional 

Transmission Operator (RTO) responsible for planning and 

reliable operation of the bulk power system serving all or 

portions of 13 states in the Mid-Atlantic and Midwestern regions 

- issued a report analyzing the impacts of the CSAPR and the 

proposed MATS rule.325 Although PJM’s analysis assumes 

substantially more retirements than EPA projects, it 

nevertheless concludes that resource adequacy is not threatened 

in the PJM region. This is particularly significant, given that 

the PJM region is one of the largest and most heavily dependent 

on coal-fueled generation in the country. The PJM analysis 

notes, as EPA has acknowledged, that even where there is 

adequate generation capacity on a regional basis, localized 

reliability issues may emerge in connection with retirements 

that may need to be addressed.

The EPA has reviewed industry and NERC studies suggesting, 

contrary to the EPA’s and these other groups’ analyses, that EPA 

rules affecting the power sector (including this final rule, the 

 

324 Bipartisan Policy Center, June 2011, “Environmental 

Regulation and Electric System Reliability”.

325 PJM Interconnection, August 26, 2011, “Coal Capacity at Risk 

for Retirement in PJM: Potential Impacts of the Finalized EPA 

Cross State Air Pollution Rule and Proposed National Emissions 

Standards for Hazardous Air Pollutants.”
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CSAPR, EPA’s proposed rule addressing power plant cooling water 

intake systems under section 316(b) of the Clean Water Act 

(CWA), and EPA’s proposed rule addressing coal combustion 

residuals under the Resource Conservation and Recovery Act) will 

result in substantial power plant retirements. Some of these 

studies predict that such levels of retirements will have 

adverse effects on electric reliability in some regions of the 

country. Although the specifics of these analyses differ, in 

general they share a number of serious flaws in common that call 

their conclusions into question.

First, most of these studies make assumptions about the 

requirements of the EPA rules that are inconsistent with, and 

dramatically more expensive than, the EPA’s actual proposals or 

final rules. For example, a large proportion of the retirements 

projected by several of these studies is attributable to their 

inaccurate assumption that EPA’s cooling water intake rule under 

CWA section 316(b) would require all or virtually all existing 

power plants to install cooling towers. In one study, the 

reliability effects reported are based on inaccurate assumptions 

that all existing EGUs with a capacity utilization factor of 

less than 35 percent would close, and that all in-scope electric 

generators would be required to install cooling towers within 5 

years, whereas the not-selected options with closed cycle 
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cooling in EPA’s proposal envisioned that permit authorities 

could exercise discretion to allow facilities 10 to 15 years’

time to comply. In most cases, these analyses were performed 

before the CWA section 316(b) rule or the MATS rule were even 

proposed; even analyses subsequent to the CWA section 316(b) 

proposal continue to inaccurately portray EPA’s proposed 

approach.

Second, in reporting the number of retirements, many 

analyses fail to differentiate between plant retirements 

attributable to the EPA rules and retirements of older, smaller, 

and less efficient plants that are already scheduled for 

retirement because owners have made business decisions, based in 

significant part on market conditions, not to continue operating 

them.

Third, most of these analyses fail to account for the broad 

range of responses available to address electric reliability 

concerns associated with power plant retirements, including 

upgrades to the transmission system, construction of new 

generation, and implementation of demand-side measures. These 

measures are discussed at greater length below.

As a preliminary matter, none of these situations, either 

alone or in combination, will necessarily lead to an electric 

reliability problem. There is excess generating capacity in the 
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U.S. today and in most cases an EGU that closes, either 

temporarily until it comes into compliance or permanently, will 

not cause a reliability problem. As explained above, our 

modeling of the impact of this final rule at the regional level 

projects retirements of less than one percent of nationwide 

generating capacity and confirms that there will continue to be 

adequate capacity in all 32 subregions of the country as sources 

comply with the rule.326 This analysis shows that significantly 

less capacity will close in response to the final rule than 

might have under the proposal. Moreover, the regional modeling 

of retirements demonstrates that plants that close in response 

to this rule are spread out across the country rather than 

clustered in one area.

Outside analyses have identified many of the same flaws in 

studies projecting large-scale retirements as a result of EPA’s 

power sector rules. For example, on August 8, 2011, the 

Congressional Research Service (CRS)327 issued a report concluded 

that studies that assert that EPA rules will cause reliability 

problems, often make assumptions about the requirements of the 

rules that are inconsistent with, and dramatically more 

expensive than, the EPA’s actual proposals. The CRS further 

 

326 See Technical Support Document on Resource Adequacy in this 

Docket.

327 James E. McCarthy and Claudia Copeland, Congressional 

Research Service, August 8, 2011, “EPA’s Regulation of CoalFired Power: Is a ‘Train Wreck’ Coming?”.
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noted that EPA’s rules will primarily affect units that are more 

than 40-years old, that have not yet installed state-of-the-art 

pollution controls, and that are inefficient. Many of these 

plants are being replaced by combined cycle natural gas plants, 

driven more my lower gas prices than by EPA’s regulations. The 

June 2011 Bipartisan Policy Center report referenced above 

likewise highlighted many of these same shortcomings in the 

studies in question.328

Although we do not expect to see any regional reliability 

problems, we acknowledge that there could be localized 

reliability issues in some areas – due to transmission 

constraints or location-specific ancillary services provided by 

retiring generation – if utilities and other entities with 

responsibility for maintaining electric reliability do not take 

actions to mitigate such issues in a timely fashion. There are 

many potential actions that could be taken to address this

problem and multiple safeguards to assure a reliable electricity 

supply.

First, utilities can help to assure reliability through 

proactive steps in coordination with relevant planning and 

regulatory authorities. As we said in the proposal, early 

planning is key. The industry has adequate resources to install 

 

328 Bipartisan Policy Center, June 2011, “Environmental 

Regulation and Electric System Reliability”.
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the necessary controls and develop the new capacity that may be 

required within the compliance time provided for in the final 

rule.329 Although there are a significant number of controls that 

need to be installed across the industry, with proper planning, 

we believe that the compliance schedule established by the CAA 

can be met. Many companies have begun to do the detailed 

analysis and engineering and are ahead of others in their 

compliance strategy. There are already tools in place (such as 

integrated resource planning, and in some cases, forward 

auctions for future generating capacity) that ensure that 

companies adequately plan for, and markets are responsive to, 

future requirements such as this final rule. 

Second, companies that intend to retire EGUs should 

formally notify their RTO (or comparable planning authority in 

the case of non-RTO regions), state regulatory agencies, and 

regional reliability entities as soon as possible of their 

compliance plans, particularly with regard to any planned unit 

retirements. As we said before, in most places a closing plant 

will not be a cause for concern for reliability. The same is 

true of any outages required for retrofitting of units with 

controls. To the extent there is concern, however, early 

notification will provide an opportunity for transmission 

 

329 As stated above, EPA has provided the maximum compliance time 

authorized under CAA section 112(i)(3)(A).
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planners, market participants, and state authorities to develop 

solutions to avoid a reliability problem. In RTOs with forward 

capacity markets, owner/operators that do not bid generating 

capacity that they plan to shut down will provide an advance 

signal to market participants to take action to assure adequate 

future capacity. In all regions, early and public notification 

will allow market participants, planning coordinators and state

authorities, as appropriate and in a timely fashion, to bring 

new generation on line, put demand side resources in place, 

and/or complete any transmission upgrades needed to circumvent a 

potential issue. Most RTOs only require 45 to 120 days 

notification of closure. In combined comments to EPA, 5 RTOs 

suggested that such notification should be made no later than 12 

months after this regulation is final in order to allow a smooth 

transitioning to action to avoid a reliability problem. The EPA 

strongly encourages sources to provide notice to the RTOs as 

early as possible and believes that responsible owner/operators 

should and will do the early planning for compliance and provide 

early notification of their compliance plans, especially where 

such plans include retiring one or more units.

On the supply side, there are a range of options including 

the development of more centralized power resources (either 

base-load or peaking) and/or the development of cogeneration or 
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distributed generation. Even with the current large reserve 

margins, there are companies ready to implement supply-side 

projects quickly. For instance, in the PJM region, there are 

over 11,600 MW of capacity that have completed feasibility and 

impact studies; the units representing this capacity could be 

on-line by the third quarter of 2014.330 The EPA notes, as well, 

that in the 3 years from 2001 to 2003, industry brought over 160 

GW of generation on line.331

Demand side options include energy efficiency as well as 

demand response programs. These types of resources can also be 

developed very quickly. In 2006, PJM had less than 2,000 MWs of 

capacity in demand side resources. Within 4 years this capacity 

nearly quadrupled to almost 8,000 MW of capacity.332 In addition 

to helping address reliability concerns, reducing demand through 

mechanisms such as energy efficiency and demand side management 

practices has many other benefits. It can reduce the cost of 

compliance and has collateral air quality benefits by reducing 

emissions in periods where there are peak air quality concerns.

With regard to transmission, recent experience also shows 

 

330 Paul M Sotkiewicz, PJM Interconnection, Presentation at the 

Bipartisan Policy Commission Workshop Series on Environmental 

Regulation and Electric System Reliability, Workshop 3: Local, 

State, Regional and Federal Solutions, January 19, 2011, 

Washington D.C, 

http://www.bipartisanpolicy.org/sites/default/files/Paul%20Sotki

ewicz-%20Panel%202_0.pdf, slide 6

331 {need citation}

332 BPC slides cited above – slide 5
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that, in many cases, transmission upgrades to address 

reliability issues from plant closures can be implemented in

less than 3 years. For instance, when Exelon notified PJM of its 

intention to retire four units,333 it was determined that 

transmission upgrades necessary to allow retirement of two units 

could be made within 6 months of notification, transmission 

upgrades for the third unit would require slightly over 1 year 

and transmission upgrades to allow the fourth unit to retire 

could be made in approximately 18 months.334

The CAA allows CAA Title V permitting authorities the 

discretion to grant extensions to the compliance time of up to 

one year if needed for installation of controls. See CAA section 

112(i)(3)(B)). If an existing source is unable, despite best 

efforts, to comply within 3 years, a permitting authority has 

the discretion to grant such a source up to a 1-year extension, 

on a case-by-case basis, if such additional time is necessary 

for the installation of controls. Id. Permitting authorities 

should be familiar with the operation of the 1-year extension 

provision because EPA has established regulations to implement 

the provision and the provision applies to all NESHAP. See 40 

 

333

http://www.exeloncorp.com/Newsroom/pages/pr_20091202_Generation.

aspx?k=eddystone

334 Cromby Units 1 and 2 and Eddystone Units 1 and 2 –

Deactivation Study, Updated September 7, 2010 -

http://policyintegrity.org/documents/20100907-cromby-andeddystone-retirement-study-posting-update.pdf
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CFR 63.6(i)(4)(A). 

We believe that the permitting authorities have the 

discretion to use this extension authority to address a range of 

situations in which installation schedules may take more than 3 

years including: staggering installations for reliability 

reasons or other site-specific challenges that may arise related 

to source-specific construction, permitting, or labor, 

procurement or resource challenges. Staggered installation 

allows companies to schedule outages at multiple units so that 

reliable power can be provided during these outage periods. It 

can also be helpful for particularly complex retrofits (e.g., 

when controls for one unit need to be located in an open area 

needed to construct controls on another unit). The additional 1-

year extension would provide an additional two shoulder periods

(i.e., seasons flanking annual high-demand periods) to schedule 

outages, thus enabling owners/operators to gain the full benefit 

of staggering outages in support of complex installations. The 

EPA believes that although most units will be able to fully 

comply within 3 years, the fourth year that permitting 

authorities are allowed to grant for installation of controls is 

an important flexibility that will address situations where an 

extra year is necessary. That fourth year should be broadly 

available to enable a facility owner to install controls within 
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4 years if the 3-year time frame is inadequate for completing

the installation.

As we indicated at proposal, this source category is unique 

due to the large, complex and interconnected nature of 

electrical generation, transmission and distribution, and the 

critical role of the electric grid in the functioning of all 

aspects of the economy. The grid functions as an interconnected 

system that supplies electricity to end users on a continuous 

basis. Safe, reliable operation of the grid requires 

coordination among actions taken at individual units, including 

timing of outages for the installation of controls, derating, or 

deactivation. It was for this reason that we specifically 

addressed in the proposed rule reasonable interpretations of the 

phrase “installation of controls” in CAA section 112(i)(3)(B). 

We determined that it was important to provide Title V permit 

authorities with information that might be useful if they were 

asked to authorize a fourth year for specific EGUs.

The EPA took comment on whether the construction of on-site 

replacement power could be considered the “installation of 

controls” such that a fourth year would be available while the 

replacement unit is being completed for a unit that is retiring 

(e.g., a case when a coal-fueled unit is being shut down and the 

capacity is being replaced on-site by another cleaner unit such 
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as a combined cycle or simple cycle gas turbine). After 

reviewing the comments, EPA believes that it is reasonable for 

permit authorities to allow the fourth year extension to apply 

to the installation of replacement power at the site of the 

facility. The EPA believes that building replacement power 

constitutes the “installation of controls” at a facility to meet 

the regulatory requirements.

Commenters were generally supportive of the proposed 

approach described above, but a number of commenters suggested 

several additional situations that should be considered as the 

“installation of controls” such that it would be appropriate for 

permitting authorities to grant a 1-year extension beyond the 3-

year compliance time-frame. In particular, commenters suggested 

that the 1-year extension should be available for a unit if a 

company’s compliance choice was to retire that unit but doing so 

within the 3-year time-frame caused reliability problems for any 

of the following reasons: (1) generation from the retiring unit 

is needed to maintain reliability while other units install 

emission controls; (2) new off-site generation was being built 

to replace the retiring unit, but the new generation was not 

scheduled to be operational within the 3-year time-frame and any 

gap between the time the existing unit retires and the new unit 

comes on line would cause reliability problems; and (3) 
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transmission upgrades were needed in order to maintain electric 

reliability after the unit retired but could not be completed 

within 3 years.

While the ultimate discretion to provide a 1-year extension 

lies with the permitting authority, EPA believes that all three 

of these cases may provide reasonable justification for granting 

the 1-year extension if the permitting authority determines, for 

example, based on information from the RTO or other planning 

authority or other entities with relevant expertise, that 

continued operation of a particular unit slated for retirement 

for some or all of the additional year is necessary to avoid a 

serious risk to electric reliability.

In a case where pollution controls are being installed, or 

onsite replacement power is being constructed to allow for 

retirement of older, under-controlled generation, a 

determination that an extra year is necessary for compliance 

should be relatively straightforward. In order to install 

controls, companies will have to go through a number of steps 

fairly early in the process including obtaining necessary 

building and environmental permits and hiring contractors to 

perform the construction of the emission controls or replacement 

power. This should provide sufficient information for a 

permitting authority to determine that emission controls are 
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being installed or that replacement power is being constructed. 

Because companies will need to develop this information early in 

the process and because a determination can easily be made as to 

whether the schedule will exceed 3 years, the EPA believes that 

Title V permitting authorities should be able to quickly make 

determinations as to when extensions are appropriate.

In the three cases related to retirement of a unit without 

construction of onsite replacement power, additional information 

is needed. The Title V permitting authority should request that 

the affected company or companies provide information, 

including, for example, from the RTO or other planning authority

for the relevant region, the state electric regulatory agency, 

NERC or its regional entities, and/or FERC or the DOE,

demonstrating that retirement of a particular unit within the 3-

year compliance period would result in a serious risk to 

electric reliability.

The first two situations involving a retiring unit – where 

one or more related existing units are upgrading pollution 

controls or a new unit is being constructed off-site – are 

similar to the situation we discussed in the proposed rule 

wherein a retiring unit at a facility runs an additional year 

while a replacement unit on the same site is constructed. In 

each of these situations, the retiring unit would be allowed to 
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run so a unit compliant with the rule (either a retrofitted 

existing unit or a new unit) can come on line. We believe that 

these situations may, in the appropriate circumstances, 

constitute ones in which a 1-year extension for the retiring 

unit is “necessary for the installation of controls.” In these 

two situations, however, we believe that it would be appropriate 

for the Title V permitting authority to consider reliability 

concerns as a necessary factor before granting the additional 

year because continuing operation of the retiring unit is only 

“necessary” to the extent it is required for reliability. In 

each of these situations, the permitting authority should 

determine that the retiring unit is necessary to maintain 

reliability until the new unit comes on line or the other 

existing unit is retrofitted. Title V permitting authorities may 

determine that multiple retiring units are available to maintain 

reliability, but unless all the units are necessary to address 

the issue, it would likely be unreasonable to provide the 

additional year for all the identified units. 

The third hypothetical situation identified above is one in 

which transmission upgrades are necessary to address a 

reliability issue resulting from the retirement of a unit in 

order to comply with this rule, where the upgrade cannot be 

completed by the 3-year compliance date. In terms of the 
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functionality of the electric grid, this situation has some 

similarity to those discussed above. Here, it is the completion 

of the transmission upgrades, rather than bringing another 

compliant (retrofitted or new) unit on line, that would allow 

the retiring unit to come into compliance (by retiring) without 

threatening reliability. The general objective and result is 

similar: reductions of the existing unit’s HAP emissions 

(through retirement) while maintaining electric reliability. If 

such situations develop and the reliability problem has been 

properly demonstrated, permitting authorities should consider 

whether an extension under CAA section 112(i)(3)(B) may be 

provided.

The EPA continues to believe, based on the analysis 

discussed at the beginning of this section, that most, if not 

all, units will be able to comply with the requirements of this 

rule within 3 years. The EPA also believes that making it clear 

that permitting authorities have the authority to grant a 1-year 

compliance extension where necessary, in the range of situations 

described above, addresses many of the other concerns that 

commenters have raised. The EPA believes that the number of 

cases in which a unit is reliability critical and in which it is 

not possible to either install controls on the unit or mitigate 

the reliability issue through construction of new generation, 
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transmission upgrades, or demand-side measures, within 4 years, 

is likely to be very small or nonexistent. This view is 

consistent with statements from commenters explicitly mandated 

with ensuring grid reliability.

The EPA’s authority to provide relief from the requirements 

of this final rule beyond the fourth year is limited by the 

statute. If reliability issues do develop, however, the CAA 

provides mechanisms for sources to come into compliance while 

maintaining electric reliability. One area where the EPA has 

some measure of flexibility is with respect to the exercise of 

its enforcement authorities. The Agency has used such authority

in the past to bring sources into compliance with the 

requirements of the CAA while maintaining electric reliability, 

although these authorities are not as flexible as suggested by 

some commenters.

The EPA generally does not speak publicly to the intended 

scope of its enforcement efforts, particularly well in advance 

of the date when a violation may occur. In light of the 

importance of ensuring electric reliability, however, the Office 

of Enforcement and Compliance Assurance will separately publish 

a document that articulates our intended approach with respect 

to sources that operate in noncompliance with this final rule to 

address a specific and documented reliability concerns.
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That document provides a pathway for reliability critical 

units (as such units are described in the document) to achieve 

compliance within an additional year. The result is that 

qualifying reliability critical units may come into compliance 

within up to 5 years. This pathway is structured to maintain 

reliability, to ensure CAA compliance and to increase certainty 

for sources in planning by allowing a unit owner/operator to 

determine whether it qualifies for a compliance schedule well in 

advance of the MATS compliance deadline.

The EPA believes that there will be few, if any, situations 

in which it will be necessary to have recourse to the processes 

discussed in the document just described, and that there are 

likely to be fewer, if any, cases in which it is not possible to 

mitigate a reliability issue within the further year 

contemplated under that document. However, there is always the 

possibility that some unit owner/operator will be unable to 

address its reliability issues within 5 years and there is 

always the possibility that a unit owner/operator will be unable 

to timely comply with the MATS for some other reason. Consistent 

with its longstanding historical practice under the CAA, the EPA 

will address individual non-compliance circumstances on a caseby-case basis, at the appropriate time, to determine the 

appropriate response and resolution.
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A number of commenters also raised concerns about 

inconsistencies between the compliance timelines under this 

final rule and existing state agreements with specific 

owners/operators to install pollution control equipment and/or 

retire EGUs. The EPA believes the flexibilities provided in this 

discussion allow for some discretion to address those cases, but 

that they may not be fully addressed. The EPA is supportive of 

such efforts and believes they can have important multipollutant health and environmental benefits. To the extent that 

the flexibilities discussed here do not fully address a 

particular situation, we encourage states and sources to contact 

the EPA as early as possible to discuss their individual 

circumstances.

G. Cost and Technology Basis Issues

1. Dry Sorbent Injection

Comment: Several commenters stated that there is limited 

commercial operating experience in using DSI to control acid gas 

emissions from coal-fired boilers. They suggest that the 

technology is not adequately proven for use in this application.

Other commenters disagree with statements made that DSI is 

not proven. One commenter stated that DSI is a mature 

technology. The commenter indicated that DSI is well suited for 

units that burn fuels with lower or mid-level sulfur contents, 
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and is among the viable options available for a number of 

sources to achieve the proposed HCl limits. Thus, the commenter 

believes that DSI represents a real technology control option 

for many units, and is among the suite of technology options 

that certain units will be able to employ to meet the proposed 

HCl limit.

Response: As explained in this response and elsewhere in this 

preamble, the EPA agrees that DSI technology is proven and ready 

for commercial use in controlling acid gases from coal 

combustion. One of the largest coal-burning electric utilities 

in the U.S, American Electric Power (AEP), pioneered the 

practical use of DSI with trona, a sodium-based sorbent, for SO3

mitigation. American Electric Power has implemented trona 

injection for that purpose across its entire bituminous coalfired fleet where both SCR and wet FGD systems are in place.335

Examples of coal-fired EGUs already using trona DSI to control 

SO2 emissions include NRG Energy’s Dunkirk Generating Station 

Units 1-4 and CR Huntley Units 67 and 68 in New York.336 The 

Dunkirk units range in size from 75 MW to 190 MW. Much larger 

units may also be economic when using DSI for SO2 control, as 

 

335 SO3 Control: AEP Pioneers and Refines Trona Injection Process 

for SO3 Mitigation, Coal Power, March 2007, 

http://www.coalpowermag.com/plant_design/SO3-Control-AEPPioneers-and-Refines-Trona-Injection-Process-for-SO3-

Mitigation_29.html

336 NRG Energy letter to RGGI, Inc, November 22, 2010, 

http://www.rggi.org/docs/NRG_Nov_2010.pdf
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suggested by Dominion Energy’s studies of adding DSI on two 625 

MW units at the Kincaid plant in Illinois.337 One of the largest 

suppliers of air emission control systems in the world, vouches 

that DSI is commercially proven for acid gas control:338,339

Comment: Numerous comments were received on EPA’s IPM modeling 

of DSI in the MATS analysis. A few commenters stated that DSI 

will not work on bituminous coals. Some commenters stated that 

DSI is only suitable for use on low sulfur, low chlorine western 

coals. Others stated that DSI is only likely to be used on 

relatively small units, and that larger units would use 

scrubbers for acid gas control. Several commenters expressed the 

opinion that because there is little commercial operating 

experience in using DSI to control SO2 emissions from coal-fired 

boilers, EPA’s IPM modeling assumptions on the efficacy and cost 

of the DSI control option are unjustifiably optimistic. Some 

commenters believe that DSI will not be as economic or as widely 

applicable for either SO2 or HCl control as projected by EPA’s 

IPM modeling. Commenters observe that wet or dry scrubbers for 

FGD, longer-standing control technologies for SO2 and HCl, are 

more complex systems with a much higher capital cost than DSI. 

 

337 Dominion Energy, BART Analysis for the Kincaid Power Plant, 

January 2009, http://www.epa.state.il.us/air/drafts/regionalhaze/bart-kincaid.pdf

338 Dry Sorbent Injection Systems for Acid Gas Control, Babcock & 

Wilcox, 2010, http://www.babcock.com/library/pdf/ps-451.pdf

339 Technologies for Acid Gas Control, Babcck & Wilcox, 2011, 

http://www.babcock.com/library/pdf/ps-457.pdf
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These commenters argue that the sector will need to retrofit 

many more FGD scrubbers than projected by IPM for MATS 

compliance and will therefore experience a much higher overall 

cost of compliance than projected by IPM, as well as needing 

more time and resources for retrofit construction. A few 

commenters suggested that EPA should base its MATS modeling on 

this more conservative outlook. A few commenters were concerned 

that EPA’s DSI modeling assumptions relied on performance data 

from only one DSI vendor.

Some commenters were concerned that fly ash currently sold 

for beneficial uses will become unsalable because it will be 

contaminated by injected sodium-based DSI sorbents. Two 

commenters argued that EPA’s IPM analysis understates DSI cost 

by not including the costs of foregone fly ash sales revenue and 

contaminated fly ash disposal. A few commenters observed that 

landfilling of sodium-based DSI solid wastes will produce 

leachate containing sodium and other compounds that are 

challenging to handle, thus requiring special landfill designs 

and a high cost for landfill disposal of DSI waste. 

Response: The EPA believes that its representation of DSI in 

MATS compliance modeling is reasonable, is properly limited to 

applications that are technically feasible, and reflects a 

conservative approach to modeling future use of this technology.
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The EPA disagrees that its IPM modeling of DSI is overly 

optimistic and therefore underestimates the costs of MATS 

compliance. In its IPM modeling, EPA restricts the availability 

of the DSI option to only those units that use or switch to 

relatively low sulfur coal: less than 2 lb SO2/MMBtu (see IPM 

documentation in the docket). The EPA’s IPM projections for MATS 

compliance, therefore, already include the costs of any 

additional FGD scrubbers that are economically justified and 

projected for use on units using higher sulfur coals. The EPA 

models DSI assuming fine-milled trona as the injected sorbent. 

As mentioned by several commenters, sodium bicarbonate (SBC), 

which is processed from trona, is also suitable for use with 

DSI. Sodium bicarbonate is more reactive with acid gases than 

trona. It would require less tonnage of sorbent and less tonnage 

of waste disposal than trona for the same SO2 removal effect, 

albeit at somewhat higher sorbent cost. Non-sodium based 

sorbents such as hydrated lime (calcium based) could also be 

used. Therefore, EPA’s modeling of DSI technology does not 

include the full spectrum of sorbent choices that real-world 

applications enjoy, meaning that there may be opportunities for 

lower-cost applications of DSI that are not captured in EPA’s 

projections for MATS. The EPA models DSI with trona injection 

rates corresponding to 70 percent SO2 removal for all coals, 
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assuming that an equivalent amount of sorbent is needed to 

provide 90 percent HCl removal, regardless of the low sulfur and 

chlorine content of western coals.

Senior technical staff from the EPA have carefully 

evaluated the key assumptions regarding the cost and operation 

of emission control technologies. In general, these staff 

believe that trona should have strong HCl reaction selectivity 

and, consequently, EPA’s assumed trona injection rates may be 

overstated. The extent to which this assumption may actually 

overstate DSI control costs can be observed through DSI pilot 

testing for Solvay Chemicals by the Energy & Environmental 

Research Center (EERC) at the University of North Dakota.340 The 

EERC’s testing of trona DSI on a central Appalachian bituminous 

coal (1.3 lb SO2/MMBtu) substantiates the strong HCl reaction 

selectivity of sodium-based sorbents, including trona, and 

calcium-based hydrated lime. The EERC’s pilot testing shows that 

fine-milled trona, when well mixed into 325 °F flue gas upstream 

of a FF, provides 90 percent HCl removal at a SO2 removal rate of 

less than 20 percent (as compared to EPA’s modeling assumption 

of aligning 90 percent HCl removal with sorbent injection 

designed to achieve 70 percent SO2 removal). The data show that 

 

340 Solvay Chemicals, Inc, 

HCl Removal in the Presence of SO2 Using Dry Sodium Sorbent 

Injection, 

http://www.solvair.us/SiteCollectionDocuments/presentations/2011

1214_hcl_presentation.pdf
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95 percent or higher HCl removal is readily obtained at somewhat 

higher SO2 removal rates. Similarly strong HCl selectivity 

results were obtained using trona and an ESP at 650 °F. Test 

data from United Conveyor341 on full-scale units also show these 

high HCl selectivity trends. Overall, these test data from 

multiple major vendors suggest that even if a SO2 removal rate of 

30 percent were required in order to obtain 90 percent HCl 

removal in the imperfectly mixed flow of a full-scale unit, it 

still appears that EPA’s assumed trona injection rates may be as 

much as twice as high as would actually be needed in practice 

for certain applications. It is apparent that if EPA were to reanalyze MATS compliance with DSI injection rates reduced by 50 

percent, there would be a corresponding reduction in the sorbent 

and related waste disposal costs that constitute most of the 

cost of using DSI. 

Given the EERC test data, it is also apparent that most

units that have ESPs and are burning low sulfur western coal 

could meet the HCl limit using DSI without the addition of a FF. 

If EPA were to re-analyze MATS compliance while allowing DSI use 

without the need for a downstream FF, it is apparent that there 

would be a very significant reduction in the overall number of 

 

341 United Conveyor Corporation, Dry Sorbent Injection for 

Simultaneous SO2, HCl, and Hg Removal, October 2011, 

http://unitedconveyor.com/uploadedFiles/Systems/Systems_Sub/McIl

vaine%20Multipollutant%20Removal%20Oct%202011.pdf
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FF retrofits projected, and a corresponding reduction in 

annualized capital costs. For the MATS proposal, the EPA modeled 

DSI on the assumption that all chlorine in coal converts to HCl, 

and that DSI would be the only mechanism by which the unit could 

prevent HCl from being emitted. Based on public comments and a 

more thorough review of the ICR data, the EPA has introduced in 

final MATS modeling a recognition that the relatively high 

alkalinity of ash from subbituminous and lignite coals “removes”

much of the HCl that would otherwise be emitted from combustion 

of these particular coals. The 2010 ICR data indicate that in 

some cases the ash itself removes sufficient HCl from these 

coals for MATS compliance; in effect, these acid-gas emissions 

are absorbed by coal ash and are captured by particulate control 

devices instead of being emitted in gaseous form. As a 

conservative measure, EPA’s revised final MATS modeling assumes 

that 75 percent of HCl is removed by the ash for these coals. In 

the event that ash capture in practice is more effective than 

this 75 percent assumption, then EPA’s analysis projects a 

conservatively higher level of DSI installations (and, thus, 

compliance cost) than would actually occur in practice. In any 

case, it appears that significantly less sorbent injection would 

actually be required in practice than assumed by EPA for these 

low sulfur, low chlorine coals, and that the IPM projected DSI 
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operating costs are likewise higher for these coals than would 

be experienced in practice.

The EPA models DSI with sorbent injection occurring 

downstream of an existing electrostatic precipitator (ESP). The 

existing ESP is assumed to remain in service. The model adds a 

fabric filter downstream of the DSI injection point to capture 

the small amount of PM passing through the ESP plus the reacted 

and unreacted DSI sorbent. Most of the DSI projected by IPM,

therefore, includes the costs of a retrofitted FF. This modeled 

configuration allows fly ash currently captured in ESPs to 

remain uncontaminated by DSI sorbent and, therefore, remain 

available for sale and beneficial use. The EPA conservatively 

models FF costs based on an assumed full-size system with an 

air-to-cloth ratio of 4.0. The FF costs could be somewhat less 

in practice if a smaller system (with an air-to-cloth ratio of 

6.0) were used for the reduced DSI dust loading. The EPA 

observes that some of the owners of units with ESPs may chose to 

convert existing ESPs into FFs,342 an option not modeled in IPM, 

but that would likely have a lower capital cost than a 

retrofitted FF. In the MATS proposal EPA modeled DSI with a 

waste disposal cost of $50/ton, based on a Sargent & Lundy DSI 

 

342 TW Lugar, et al., The Ultimate ESP Rebuild: Casing Conversion

To a Pulse Jet Fabric Filter, a Case Study, Electric Power 

Conference, May 2009, 

http://www.cecoenviro.com/uploads/ESP%20to%20Fabric%20Filter%20B

aghouse%20Conversion%20-%20Buell%20Case%20History.pdf
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cost model prepared for EPA (see proposal IPM documentation in 

the docket). The EPA has continued to model DSI at this waste 

disposal cost for analysis of the final rule. However, recent 

discussions between senior technical staff from the DOE and the 

EPA have suggested that in some situations sodium sulfates, that 

would be formed by the injection of trona, could potentially 

leach out of the fly ash/sorbent mixture on contact with water. 

Although the technical staff recognized that these concerns are 

more relevant to bituminous coal-fired units where ashes are not 

cementitious, unless mixed with limestone or lime, they 

suggested that the impacts of potentially higher disposal costs 

be evaluated. Based on public comments, further investigations

by Sargent & Lundy, and suggestions from the EPA and DOE 

technical staff, EPA’s analysis of the final rule has included 

an IPM sensitivity case using a DSI waste disposal cost of 

$100/ton. The sensitivity case indicates that a 100 percent

increase in assumed DSI waste disposal cost produces slightly 

less than a 1 percent increase in the projected cost of the 

rule.

Comment: A few commenters expressed the concern that there is an 

inadequate supply of trona to support DSI operations at the 

levels projected by the EPA for MATS compliance.

Response: The EPA projects that just over 50 GW of coal-fired 
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capacity might retrofit with DSI for MATS compliance, thus 

reducing SO2 emissions by about 1 million tons per year. Based on 

conservatively high trona injection rates, as discussed above, 

the EPA estimates that the amount of trona required to support 

DSI operations at this level is about 4 million tons per year. 

By comparison, the trona mining industry in the U.S. has a 

demonstrated production capacity of at least 18 million tons 

annually, and was running well below that capacity (16.5 million 

tons) in 2010.343,344 If the EPA’s assumed trona injection rates 

are as much as 50 percent greater than actually needed for at 

least 90 percent HCl control, as discussed above, and given that 

some subbituminous coals will apparently need little or no 

sorbent injection for HCl control, there may already be an 

adequate surplus of trona production capacity to support DSI for 

MATS compliance. The EPA, therefore, concludes that trona supply 

for DSI is either already adequate, or will require at most a 

small increase in production capacity.

For all of these reasons, the EPA believes that its 

representation of DSI in MATS compliance modeling is reasonable, 

is properly limited to applications that are technically 

feasible, and reflects a conservative approach to modeling 

future use of this technology.

 

343 http://www.wma-minelife.com/trona/tronmine/tronmine.htm

344 http://www.wmaminelife.com/trona/TronaPage2/trona_production.htm
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2. Economic Hardship

a. Job losses and economic impacts.

Comment: Several commenters indicated that they believe the 

proposed rule will weaken industry, cause job losses and hurt 

power consumers. One commenter reported that the proposed rule 

will affect 1,350 coal and oil-fired units at 525 power plants 

and that NERC reports that by 2018 nearly 50,000 MW of capacity 

will be retired by the proposed rule. Many of these commenters

compared the cost estimated by EPA to a variety of other sources 

that estimate substantially higher costs of the rule. The 

commenters expressed concern that electricity price increases 

are likely to be up to 24 percent in some regions as a result of 

the proposed rule. In addition to the economic difficulty the 

proposed rule could place on consumers, the commenter believes 

that many in the energy sector will lose their jobs due to coalfired capacity losses. The commenters believe the effects on 

coal-fired plants in the Southeast especially will mean the loss 

of high-paying, high-skilled jobs and drastic price increases in 

energy costs. Additionally, commenters expressed concern that 

increased electricity and natural gas prices would impact 

businesses in multiple sectors across the country.

Response: The EPA disagrees with the estimates presented by the 

commenters. The EPA has updated its analysis to reflect the 
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final MATS. The Agency estimates the annual costs of the final 

rule in 2015 to be $9.6 billion in 2007 dollars. The estimate of 

early retirements of coal-fired units due to this rule is 4.7 

GW, lower than the level estimated at proposal. Both of these 

estimates were prepared using the IPM, a model that has been 

extensively reviewed and has been utilized in several 

rulemakings affecting the power generation sector over the last 

15 years. The Agency’s analyses are credible and accurate to the 

extent possible, and all assumptions and data are made public. 

Limitations and caveats to these analyses can be found in the 

RIA for this rule.

The EPA estimates that there will be an increase of 3.1 

percent in retail electricity price on average in the contiguous 

U.S. in 2015 as an outcome of this rule, with the range of 

increases from 1.3 percent to 6.3 percent in regions throughout 

the U.S. No region of the U.S. is expected to experience a 

double-digit increase in retail electricity prices in 2015 or in 

any year later than that, according to the Agency’s analysis, as 

a result of this rule. To put this in context, the roughly 3 

percent incremental increase in aggregate end-user electricity 

prices projected to occur over the next 4 years is about the 

same as the 3 percent absolute average change in total end-user 
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electricity prices observed on an annual basis.345 Furthermore, 

the roughly 3 percent incremental price effect of this rule is 

small relative to the changes observed in the absolute levels of 

electricity prices over the last 50 years, which have ranged 

from as much as 23 percent lower (in 1969) to as much as 23 

percent higher (in 1982) than prices observed in 2010.346 Even 

with this rule in effect, electricity prices are projected to be 

lower in 2015 and 2020 than they were in 2010.347

The Agency found that the readily discernible impact on 

long-term employment nationally within the most directly 

affected sectors should be small and the EPA also estimated that 

about 46,000 job-years348 of one-time construction labor could be 

supported or created by this rule. This includes jobs 

manufacturing steel, cement and other materials needed to build 

pollution control equipment, jobs creating and assembling 

pollution control equipment, and jobs installing the equipment 

at power plants. Potential job increases from increased output 

 

345 EIA Annual Energy Outlook 2010 annual total electricity 

prices from 1960 to 2010, Table 8-10.

346 Ibid, EIA AEO 2010, Table 8-10.

347 Ibid, EIA AEO 2010, Table 8-10 for price levels; and Chapter 

3 of the RIA for electricity price differential.

348 A “job-year” is a combined measure of jobs and job duration 

which is equivalent to one person being employed for one year. 

For example, 2 job-years could represent two years of employment 

for one worker, one year of employment for two workers, or 6 

months of employment for four workers. Estimates of employment 

changes that involve non-permanent workers are usually reported 

in job years to give a sense of the total employment effects.
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by lower-emitting facilities (such as increased generation from 

well-controlled coal-fired plants that replace generation from 

older coal-fired plants) are expected to partially or fully 

offset potential job losses resulting from reduced output from 

higher-emitting facilities. The EPA analysis projects a net 

change in the directly affected EGU sector of between 15,000 net 

jobs lost to 30,000 net jobs gained on an annual basis.349 See 

Chapter 6 of the RIA for further details.

The EPA has also looked at the possibility that changes in 

the price of electricity may influence the levels and geographic 

distribution of downstream economic activities, and associated 

employment. Projecting how potentially higher electricity prices 

may affect various downstream economic activities in particular 

regions as a result of this rule is challenging for several 

reasons: (1) there are significant uncertainties regarding 

projections of consumer- and location-specific electricity price 

changes in response to future firm-specific compliance 

strategies; (2) the availability of competitively-priced 

alternative energy sources (including energy conservation) and 

less electricity-intensive substitute goods and services may 

significantly mitigate potentially adverse economic consequences 

 

349 It should be noted that if more labor must be used to produce 

a given amount of output, then this implies a decrease in labor 

productivity. A decrease in labor productivity will cause a 

short-run aggregate supply curve to shift to the left, and 

businesses will produce less, all other things being equal.
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resulting from projected increases in electricity prices in ways 

which are not captured effectively in currently available 

models; and (3) available modeling tools are not configured to 

capture the effects over time of economically significant 

effects of cleaner air (e.g., reductions in medical expenditures 

and improvements in labor productivity resulting from fewer lost 

work days) achieved by rules evaluated using single target year 

criteria pollutant and/or HAP benefits projections. After 

considering these methodological limitations, the Agency 

concludes that there is not a satisfactory methodology for 

projecting the downstream economic (including employment) 

effects of any changes in electricity prices due to this rule.

We expect the downstream economic effects of this rule to 

be small because electricity is only a small factor in the 

production of most goods and services.350 A 3 percent increase in 

end-user electricity prices translates to a much smaller effect 

on prices and potential output of goods and services from endusers of electricity. Over time, the incremental effect of this 

rule on electricity prices is projected to diminish 

significantly; for example the difference in expected prices is 

projected to narrow from 3.1 percent in 2015 to 2.0 percent in 

 

350 BEA. (2007b). Commodity-by-Industry Direct Requirements after 

Redefinitions, 2002. Available in: 2002 Summary Tables, 2002 

Benchmark Input-Output Data. Retrieved from 

http://www.bea.gov/industry/io_benchmark.htm#2002data
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2020 as shown in Chapter 3 of the RIA.

Despite the absence of a satisfactory methodology for 

quantifying the potential economy-wide effects (including 

employment) of any potential increases in electricity prices 

resulting from this rule, the EPA expects the incremental 

effects of this rule on electricity prices to be small given the 

projected electricity price increases relative to historical 

levels and volatility in end-user electricity prices. Based on 

these projections and contextual information, the Agency 

believes that the incremental effects on electricity prices and 

economic activity of this rule are likely to be small relative 

to other factors influencing electricity prices, overall 

employment, and other aspects of economic activity.

Comment: Several commenters considered the proposed rule to be a 

tax on the American public, since utilities implementing 

upgrades will pass the costs on to the consumer. Commenters 

questioned the preference of Americans to subsidize renewable 

energy sources and put money into the proposed rule instead of 

other environmental programs with greater benefits. Commenters 

explained that the tax-like price increase reduces income of 

energy consumers and depresses business development. The 

commenters used California as an example of a state that uses 

low rates of coal-based electricity and cites companies that 
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have left the state as a result of substituting higher cost 

forms of electricity for coal. A commenter stated that coalderived energy will rapidly become more expensive, especially in 

the “rust belt” and Southeast region, as can be seen by the rate 

increase already requested in Louisville. A commenter believes 

the “indirect taxation” limits the ability of the economy to 

absorb the cost of retrofitting and new capacity projects, 

lowers discretionary spending and leads to job losses and lost 

tax revenues, given the restrictive timeframe for compliance.

Response: The Agency does not agree that this rule creates or 

alters any taxes on affected sources required under this rule to 

reduce their emissions of toxic air pollutants, nor are taxes 

created or altered or imposed on consumers of electricity which 

is provided to the market by affected sources. Moreover, unlike 

a tax, this rule does not generate government revenue. The rule 

does, however, indirectly address the problem of the

“externality cost” of higher health risks and other adverse 

effects on the populations exposed to toxic air pollution 

emissions from affected sources. This rule may have the effect 

of reduce or eliminate a market distortion that provides an 

implicit subsidy to affected facilities. This implicit subsidy 

results from the fact that some facilities currently can avoid 

the costs of toxic air pollution controls by imposing higher 
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health and other costs on those who are exposed to higher levels 

of toxic air pollution. The Agency also disagrees with the 

implication that the costs incurred by less-controlled sources 

to bring their toxic air emissions in line with their bettercontrolled competitors will lead to significant or debilitating 

changes in market and economic conditions. The Agency’s estimate 

of the potential increase in retail electricity price is an 

average of 3.1 percent in 2015, with a range of increases by 

region from 1.3 percent to 6.3 percent. As shown in Chapter 3 of 

the RIA, the higher rates of potential electricity price 

increase tend to occur in those regions where electricity prices 

have been relatively low, due to some extent to reliance on 

coal-fired units which have been cheaper to operate due to 

underinvestment in toxic air pollution controls.

352 As shown in 

Chapter 3 of the RIA, all regions with year 2015 projected 

percentage increases in retail electricity prices above the 

contiguous U.S. average are also projected to have baseline 

retail electricity prices which are below the contiguous U.S. 

average price level in that year. In addition, natural gas 

prices will only increase by 0.3 to 0.6 percent on average over 

the time horizon of 2015 to 2030. As discussed above, for 

consumers of electricity in the commercial and industrial 

sectors, electricity tends to be a fairly small fraction of 

 

352 http://www.epa.gov/airmarkets/images/CoalControls.pdf
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total costs of production, implying that the average projected 

electricity price increase of 3 percent will lead to only a 

small fractional change in the costs of providing goods and 

services to the economy. While some residential electricity 

consumers may similarly see a small price increase in retail 

electricity prices, it should be noted that these consumers tend 

to reside in the same area or region as the affected facility 

and so will also experience the improvement in air quality from 

the reductions due to the rule. The reduction in health risk and 

other improvements to quality of life associated with lower 

exposure to toxic and other air pollutants achieved by this rule 

will confer benefits on these consumers which include lower 

risks of premature mortality, lower morbidity, and improved 

productivity and competitiveness of U.S. workers due to 

reduction in work days lost to air pollution-related illness. 

The benefits of these improvements are projected to exceed costs 

of compliance by affected sources by at least six-fold. The 

potential price increases in electricity and natural gas should 

be considered in light of the substantial health, welfare, and 

economic benefits achieved by this rule. 

Comment: Many commenters expressed support for the EPA’s impact 

analysis and disputed claims by other commenters that the 

projected rule will harm economic growth. A number of commenters
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mentioned testimonials by power company CEOs stating that the 

proposed rule will not affect the economic health of the 

industry and a survey showing nearly 60 percent of the coalfired units already comply with the EPA’s proposed Hg standard, 

and several other meaningful quotes from utility executives. The 

commenters also pointed out that 17 states already require 

plants to address Hg pollution, with some imposing more 

stringent emission limits than the EPA proposes. The commenters

believe that utilities use the threat of power plant closures 

and lost jobs to delay Hg reductions from coal-fired plants. 

Commenters also believe that the rules will drive innovation and 

job creation as new technologies to reduce pollution are 

created. Several commenters quoted the Economic Policy Institute 

finding that the proposed rule will increase job growth by 

28,000 to 158,000 jobs by 2015 (including approximately 56,000 

direct jobs and 35,000 indirect jobs), the University of 

Massachusetts study that showed an increase in 1.4 million jobs 

in 5 years, and the Constellation Energy Group installation 

project that employed nearly 1,400 skilled workers. Commenters

also cited the University of Massachusetts study statement that 

a net gain of over 4200 long-term operation and maintenance jobs 

will result.

Several commenters observed that the positive impacts of 
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the rule strongly favor its adoption. These commenters stated 

that, contrary to the unfounded assertions by critics of EPA and 

the rule, EPA has conducted a technically sound and conservative 

benefit-cost analysis showing that the proposed rule’s estimated 

benefits are at least five times as high as its costs. One 

commenters stated, “With sound, albeit unduly conservative, 

econometric modeling, EPA has also determined that the Toxics 

Rule will promote economic growth and create jobs in both the 

long and short term.” Two commenters cited the EPA impact 

analyses by Dr. Charles Cicchetti which confirm this finding and 

state that the analysis underestimates the rule’s net benefits 

and positive impacts on the nation’s economy. By considering 

some benefits not monetized in the EPA analysis, Dr. Cicchetti 

concludes that the proposed rule will create $52.5 to $139.5 

billion in net benefits annually, create 115,200 jobs, generate 

annual health savings of $4.513 billion, annual increases in GDP 

of $7.17 billion and $2.689 billion in additional annual tax 

revenues, and spur innovation and modernization of EGUs. The 

commenters state that the study findings show no need to delay 

implementation of the rule or needlessly duplicate economic 

analyses already completed.

Commenters reported that multiple researchers confirmed 

that the EPA’s estimates of economic stimulus are conservative 
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and that the proposed rule will stimulate job growth. A 

commenter quotes Dr. Josh Bivens of the Economic Policy 

Institute, who also found that EPA’s conclusions were 

conservative. Dr. Bivens concluded, “The EPA RIA on the proposed 

toxics rule makes a compelling case that the rule passes any 

reasonable cost-benefit analysis with flying colors—the 

monetized benefits of longer lives, better health, and greater 

productivity dwarf the projected costs of compliance...Whether 

regulation in general and the toxics rule in particular costs 

jobs is an empirical question this paper attempts to answer. In 

particular, this paper examines the possible channels through 

which the proposed toxics rule could affect employment in the 

United States and finds that claims that this regulation 

destroys jobs are flat wrong: “The jobs-impact of the rule will 

be modest, but it will be positive.” His report details the 

following major findings:

1. The proposed rule would have a modest positive net impact 

on overall employment, likely leading to the creation of 

28,000 to 158,000 jobs between now and 2015.

2. The employment effect of the [MATS] on the utility industry 

itself could range from 17,000 jobs lost to 35,000 jobs 

gained.

3. The proposed rule would create between 81,000 and 101,000 
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jobs in the pollution abatement and control industry (which 

includes suppliers such as steelmakers).

4. Between 31,000 and 46,000 jobs would be lost due to higher 

energy prices leading to reductions in output.

5. Assuming a re-spending multiplier of 0.5, and since the net 

impact of the above impacts is positive, another 9,000 to 

53,000 jobs would be created through re-spending.

Response: The EPA thanks the commenters for these observations. 

The Agency’s estimates of employment impacts, found in the RIA 

for the rule, are smaller than those identified by the some 

commenters, though the EPA uses a different methodology that 

focuses on impacts specific to the electric power sector. 

b. Impacts on low-income consumers.

Comment: Commenters expressed concern that the EPA’s overview of 

the price increases does not consider the hardships that will be 

the reality of increased prices on low-income or fixed-income 

households or small businesses. The commenter reports increases 

of $90 million in capital costs, $11.4 million in annual 

operating costs and $6.4 million in annual debt service costs to 

achieve compliance, which will lead to a 13 percent increase in 

rates for the proposed rule, and a 41 percent increase for all 

proposed and new regulation compliance costs. The commenter

argues against the EPA’s view that energy efficiencies will 
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offset rate increases, because low income customers will need to 

use less electricity due to economic necessity. The commenter

also sees large price increases for customers if units are 

converted to natural gas, which is approximately 2.5 times more 

expensive than the coal that the commenter currently uses to 

generate electricity.

Response: The EPA’s estimates of increase, relative to the 

baseline, in the retail electricity price range from 1.3 percent 

to 6.3 percent regionally in 2015, with an average increase 

nationwide of 3.1 percent in 2015. Low-income households will 

thus see some increase in electricity price, but this increase 

should be modest. In addition, the increase in the price of

natural gas as a result of this rule is expected to be 0.3 to 

0.6 percent over a time horizon of 2015 to 2030. This increase 

in price is low enough that electricity customers should not 

experience a major increase in price resulting from any modest 

changes to electricity generated by natural gas. The roughly 3 

percent incremental price effect of this rule is small relative 

to the changes observed in the absolute levels of electricity 

prices over the last 50 years, which have ranged from as much as 

23 percent lower (in 1969) to as much as 23 percent higher (in 

1982) than prices observed in 2010.353

 

353 EIA Annual Energy Outlook 2010 annual total electricity prices 

from 1960 to 2010, Table 8-10.
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c. State or regional impacts.

Comment: Multiple commenters expressed concern over the impact 

of the rule on electricity prices and reliability in specific 

states or regions. These commenters were concerned that these 

impacts would adversely affect specific industries such as 

construction and manufacturing. One commenter suggested the EPA 

consider regional differences that will impact system 

reliability and costs, such as the increased impacts on regions 

relying heavily on coal and oil and encourages cooperation 

between the EPA and state and federal energy and environmental 

regulators.

Response: The Agency has studied possible impacts on resource 

adequacy as a result of this rule, and has determined that these 

impacts should not be significant. Furthermore, industry, along 

with relevant federal agencies, has the tools needed to address 

any reliability concerns. The Agency has prepared an updated 

feasibility TSD in support of the final rule, which is in the 

docket for this rulemaking.

354 The Agency has considered impacts 

on a regional basis as part of its overall analyses done using 

the IPM; these results are documented in the RIA for the rule 

and in the feasibility TSD.

The EPA’s analysis shows that retail electricity price 

 

354 See “An Assessment of the Feasibility of Retrofits for the 

Mercury and Air Toxics Standards Rule” in the docket.
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increases will not fall disproportionately on a specific region. 

In fact, those regions experiencing the largest change in prices 

are projected to have retail electricity prices below the 

national average both in the absence of MATS and after the 

implementation of MATS. In Chapter 3 of the RIA, the EPA 

presents retail electricity prices by region in 2015, for both 

the base case and MATS policy case. The six regions that are 

projected to have retail electricity prices above the national 

average price in 2015 in the absence of MATS are projected to 

have increases that are below the national average increase 

following the implementation of MATS. Those regions that have 

projected retail electricity price increases that are above the 

national average are all projected to have retail electricity 

prices below the national average in the absence of MATS.

Comment: A commenter quoted National Mining Association

statistics showing coal is responsible for $65.738 billion in 

annual economic activity, produces 1,798,800 jobs and $36.345 

billion in annual labor income. The commenter reports that 

regions such as Appalachia, the Midwest and Rocky Mountain West 

will be significantly affected by the proposed rule, including 

increased unemployment. Other commenters stated that communities 

near existing coal-fired generation units will be especially 

hard-hit if the plants are permanently retired. The communities 
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will suffer from job loss and diminished tax revenue.

Response: The Agency’s analysis, as found in the RIA, shows that 

impacts to these regions are mixed. For Appalachia, coal 

production is projected to fall by 6 percent in 2015, while the 

Western coal producing region will experience a decrease of 3 

percent in production in 2015. The Interior region is projected 

to see a 9 percent increase in production. Retail electricity 

prices are expected to increase by 1.3 percent to 6.3 percent in 

various parts of the country in 2015. Also, the estimated number 

of early retirements according to the Agency that may result 

from this rule is 4.7 GW in 2015, or less than 2 percent of all 

U.S. coal-fired capacity in that year. Thus, there may be some 

negative impacts from this rule in some regions, but these same 

regions will also experience some of the benefits, such as 

reduced premature mortality from less exposure to PM2.5 emissions 

as shown in Chapter 5 of the RIA. As discussed previously, the 

EPA’s analysis shows that retail electricity price increases 

will not fall disproportionately on a specific region. In fact, 

those regions experiencing the largest change in prices are 

projected to have retail electricity prices below the national 

average both in the absence of MATS and after the implementation 

of MATS.

The results of the EPA’s employment analysis, found in 
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Chapter 6 of the RIA, indicate that the final MATS has the 

potential to provide significant short-term employment 

opportunities, primarily driven by the high demand for new 

pollution control equipment. While the employment gains related 

to the new pollution controls are likely to be tempered by some 

losses due to certain coal retirements, some of these workers 

who lose their jobs due to plant retirements could find 

replacement employment operating the new pollution controls at 

nearby units. Finally, job losses due to reduced coal demand are 

expected to be offset by job gains due to increased natural gas 

demand, resulting in a small positive net change in employment 

due to fuel demand changes.

While shifts in employment are difficult for those directly 

affected, and the Agency remains concerned about the challenges 

job shifts can bring to the individuals affected, Bureau of 

Labor Statistics data indicate that compliance with pollution 

control requirements is a relatively very small contributor to 

overall employment shifts in the U.S. economy. Specifically, the 

main cause of mass layoffs over the last four years according to 

2007 to 2011 Bureau of Labor Statistics data is “lack of 

business demand,” accounting for over 40 percent of the layoffs 

reported by industry. In contrast, all types of regulatory 

actions (including health, safety, and environmental) by all 
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levels of government (Federal, State, local) combined were cited 

as the primary factor in only 0.2 percent of mass layoffs over 

the same period.355

d. Retirements of coal-fired EGUs and shutdowns.

Comment: A commenter discussed the economic factors behind EGU 

retirements. These factors include the cost of alternative 

generation using natural gas, the cost of implementing demand 

response measures that can be bid into capacity markets, and the 

cost of continuing to generate power from an existing unit. The 

commenter states that regardless of the costs associated with 

the Toxics Rule and other EPA electric power industry 

regulations, some power plants were already economically 

unsustainable. The commenter quotes M.J. Bradley, who points 

out, “[o]f the 122 coal units in PJM with capacity less than or 

equal to 200 MW, 35 failed to recover their avoidable costs and 

another 52 were close to not recovering those costs. Therefore, 

in PJM...in addition to approximately 10 GW of coal generation 

that has or will be retired during the 7 years from 2004 to 

2011, another 11 GW faces a troubling economic outlook.” The 

commenter provides confirmation of this by the most recent PJM 

capacity auction, where approximately 6.9 fewer GW of coal-fired 

capacity cleared the auction (1.85 fewer GW were offered) as 

 

355 US Bureau of Labor Statistics, 2011. Extended Mass Layoffs in 

2010. http://www.bls.gov/mls/mlsreport1038.pdf.
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compared with the prior year’s auction, and an additional 4.836 

GW of new demand response (energy efficiency) resources cleared 

the auction. Thus, the commenter states, some claims linking 

retirements to the MATS are overstated and misleading. The 

commenter gives the example of the American Electric Power 

attempt to link its planned plant closures to the MATS, but 

those plants already are slated to either close or to upgrade 

controls to comply with existing laws. The commenter goes on to 

quote three independent studies that support the finding that 

over 50 percent of the fleet is equipped with scrubbers and the 

number will increase to nearly 2/3 by 2015. 

Response: The EPA agrees with the findings of the independent 

studies mentioned by the commenter.

e. Impacts on mining.

Comment: Multiple commenters mention the proposed rule’s impact 

on mining. One commenter mentioned increasing energy costs for 

the U.S. mining industry, resulting in fewer projects and 

associated jobs, as well as increasing dependence on foreign 

mineral resources. Commenters see mining impacts being 

disproportionally large for lignite mines, which are dependent 

on their co-located lignite-fired power plants. The commenters

state that if the plant closes, there is no market for the 

lignite and the mine will also close, displacing plant workers. 
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These impacts are largest in Texas, the largest coal consuming 

state and fifth largest coal producing state, as well as a 

deregulated electricity market. One commenter pointed out that 

the Texas coal market provided a buffer against natural gas 

price volatility and in particular believes the proposed rule 

does not take into account the emission reductions already 

achieved by industry in general and their company in particular. 

A commenter stated that impacts will be magnified in Texas, 

since it is the largest coal consuming state and mines lignite. 

A commenter indicated they believe it is unclear the extent to 

which EPA includes the impacts on the mining industry that will 

result from this rule.

Response: The Agency presents impacts on the coal mining sector 

from this rule in the RIA. Given the modest increase in coal and 

other energy costs associated with the rule, the Agency does not 

expect widespread impacts on coal mining. The Agency’s modeling 

accounts for all emission controls and programs installed and/or 

implemented up through December 2010, including those in Texas. 

F. Flexible regulations.

Comment: Several commenters expressed concern over the potential 

impacts of the regulation and believe that the requirements 

should be more flexible in order to mitigate these impacts.

Response: The EPA believes the requirements of the final rule 
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have been made as flexible as possible consistent with the CAA. 

The final rule allows some flexibility, including allowing 

averaging across units in the same subcategory at a facility, 

allowing for an option of an input or output standard for 

existing units, and allowing for alternative compliance options 

(e.g., for coal, filterable PM or total non-mercury metallic HAP 

or individual HAP metals). In addition, the Agency is not 

prescribing specific technologies as part of this final rule, 

but instead requiring emissions limitations be met. This 

approach allows the industry to find the most cost-effective 

approach to meeting the requirements while ensuring considerable 

public health benefits.

g. Temporary vs. permanent jobs.

Comment: A commenter expressed disagreement with the EPA 

prediction of new jobs created, because the commenter believes 

far more plants will shut down than the EPA predicts, resulting 

in higher job losses. The commenter also pointed out that while 

jobs running power plants are permanent, the jobs predicted to 

be created by the proposed rule are short term construction 

jobs, and will all occur in the same short timeframe for 

compliance. The commenter also stated that the EPA estimate does 

not include the opportunity cost of lost construction jobs due 

to new power plants that will not be constructed due to the 
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proposed rules.

Response: The Agency believes that the employment impacts of the 

final rule will be small, as has been the case historically with 

regards to environmental regulation. The Agency does provide an 

estimate of the long-term employment impacts to the electric 

power sector in the RIA for the rule, and that estimate shows a 

range of impacts from 15,000 net jobs lost to 30,000 net jobs 

gained (all annual), but also recognizes important limitations 

to these estimates. The Agency’s estimate of impacts to shortterm jobs, including those in construction, accounts for both 

losses and gains that result from the rule. This is shown in 

Chapter 6 of the RIA.

Comment: Commenters believe that installation of new pollution 

controls would be a job-growth opportunity in their states 

because money spent on controls for power plants creates highquality jobs in steel, cement and other materials, as well as in 

the assembling of the equipment as well as installing and 

operating it. A commenter shares the Alabama Fisheries 

Association estimate that the water-based recreation industry 

brings in over $1 billion per year to the state’s economy though 

the state ranks third for imperiled fish with 61 bodies of water 

cited for Hg contamination. The commenter believes the HAP

accumulating in the waterways threatens the industry with 
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permanent job-losses and lost revenue.

Response: The Agency agrees with the commenter that the 

reduction in HAP that will take place as a result of the rule 

over time will help to improve waterways in Alabama and thus 

help the water-based recreation in that state. More information 

on the benefits of Hg and other HAP reductions can be found in 

Chapter 4 of the RIA for the rule. The Agency also agrees with 

the commenter that the addition of control equipment for EGUs 

may stimulate employment in a variety of industries.

h. Natural gas.

Comment: A commenter states that natural gas use is only an 

option in places where infrastructure exists to supply 

sufficient natural gas to the EGU and other local needs and 

reports that year-round reliable gas delivery is rare due to 

requirements to meet the other needs. The commenter says that 

gas interruptions are prevalent in the winter, but can happen 

year-round, and the costs of establishing a natural gas line to 

a power plant can be tens of millions of dollars or more, and 

moving a plant to a gas source can take many years. The 

commenter describes the options for a Norwalk Harbor plant, and 

explains that the modifications are costly and difficult even 

before considering the modifications needed to alter the boiler 

and fuel supply system to allow natural gas combustion.
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Response: The final rule does not prescribe either pollution 

control technologies to be used, nor does it dictate the types 

of fuels that should be burned. The requirements of the final 

rule are designed to allow industry to find the most costeffective approach to addressing harmful emissions that are 

covered by this action. The Agency believes that cost-effective 

technologies exist today and have been deployed on many power 

plants, and utilities will be able to find intelligent solutions 

to address harmful emissions. The EPA has provided supporting 

information as part of the preamble and RIA for this rule, along 

with the feasibility TSD, which demonstrate the availability and 

performance of technologies to meet the requirements of the 

final rule.

Comment: A commenter discusses the factors that could lead to 

higher natural gas prices not currently reflected in the EPA 

impact projections, including industrial load and demand not 

rebounding to 2008 levels and the influence of liquefied natural 

gas exports. The commenter asks that the EPA address a variety 

of factors related to its natural gas assumptions.

Response: The Agency has fully documented its assumptions and 

framework for modeling natural gas in IPM for both the proposed 

and final MATS. This information can be found in Chapter 10 of 

the IPM documentation 
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(http://www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter10.pdf). The documentation provides a 

thorough overview of the natural gas module, describes the very 

detailed process-engineering model and data sources used to 

characterize North American conventional, unconventional, and 

frontier natural gas resources and reserves and to derive all 

the cost components incurred in bringing natural gas from the 

ground to the pipeline. Also documented are the resource 

constraints, liquefied natural gas (LNG), demand side issues, 

the natural gas pipeline network and capacity, procedures used 

to capture pipeline transportation costs, natural gas storage, 

oil and natural gas liquids (NGL) assumptions, and key gas 

market parameters.

i. Compliance timeline and general timeline.

Comment: A commenter states that the proposed rule will require 

costs be passed on to consumers, meaning state public utility 

commissions will be flooded with requests for rate increases 

from utilities trying to recover expenditures. The short 

deadline will also result in a large number of extension 

requests made to state permitting authorities, further burdening 

them.

Response: The compliance date for this rule for existing sources 

will be 3 years and 60 days after publication of the final rule 
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in the Federal Register, or approximately March 2015. Thus, 

there will be some time before the impacts of this rule such as 

any increase in retail electricity prices become a concern. It 

also should be noted that increases in retail electricity prices 

will be 3.1 percent on average in 2015, with a range regionally 

from 1.3 percent to 6.3 percent.

Comment: A commenter reports that they will need to install addon pollution controls to meet the proposed emission standards as 

well as implement other physical or operational changes. The 

commenter expresses concern about the number of pre-construction 

steps that would be required, as well as the new construction 

activities and the challenges of scheduling sequence relative to 

interconnections and other tie-in considerations involved in 

compliance.

Response: The Agency has addressed concerns with the feasibility 

and timing of control installations in its report on the subject

(see feasibility TSD contained in the docket for this rule).

Comment: Multiple commenters do not believe that labor 

availability will constrain control installation in the required 

timeframe and cites an Institute of Clean Air Companies (ICAC)

response that it will not for these reasons:

1. the power sector has demonstrated ability to install large 

number of systems in short time period;
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2. the majority of coal plans have installed control systems 

already;

3. fewer resource and labor-intensive control options being 

used for compliance; and

4. end users have utilized cost reducing and implementation 

efficiency strategies for efficient deployment of 

technologies.

Another commenter states that a wide range of technical and 

economically feasible practices and technologies are available 

currently to meet the emission limits and are in use around the 

country.

Response: These comments are generally consistent with the 

conclusions of the Agency’s analyses on feasibility of control 

installations for this rule as found in the feasibility TSD in 

the docket for this rulemaking.

j. Burden outweighs environmental gain.

Comment: Several commenters state that the EPA has no data 

relating to benefits from reducing non-mercury HAP, so the costs 

of the proposed rule exceed the HAP benefits by 29,000 times. 

One commenter states that the impact analysis was largely 

focused on Hg with little support for other HAP reductions and 

failed to provide account of true costs and benefits.

Response: While we are not able to monetize the benefits from 
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reductions of non-mercury HAP that will take place, these 

important effects are discussed qualitatively in Chapter 4 of 

the RIA. The quantified benefits of this rule include the 

reductions in non-HAP emissions such as SO2 and PM2.5 that will

occur as a co-benefit of this rule as modeled by EPA. The total 

benefits are estimated to outweigh the total annual costs of the 

rule by a margin of either 3 to 1 or 9 to 1, depending on the 

benefits estimate and discount rate used. These reductions are 

credible and are considerable in size. The estimates of these 

benefits reflect the latest scientific understanding on the 

subject. More information on the estimates and the methodology 

for their preparation can be found in the RIA for the rule.

Comment: Several commenters consider the proposed rule to be the 

most expensive clean air rule ever. They point out the estimated 

$10.9 billion annual cost in 2015 and approximate 1,200 existing 

coal-fired EGUs affected, both of which were estimated by the 

EPA. Commenters believe the EPA’s estimates are incorrect and 

the true cost will be far more, due to cumulative effects of all 

proposed power sector rules, and indirect costs from job losses, 

reduced productivity and competitiveness resulting from 

electricity costs. They ask the EPA to keep these high costs in 

mind when evaluating impacts of the proposed rule and consider 

the costs with respect to the benefits. One commenter requests 
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that the EPA explain how its approach utilized “the best 

available techniques to quantify anticipated present and future 

benefits and costs as accurately as possible” and includes

analyses by EIA, EEI, NERC, NERA, Credit Suisse, ICF, and Burns 

& McDonnell.

Response: As noted earlier, the Agency did not prepare a 

cumulative impact analysis to accompany the rule for the 

following reasons: 1) the various EO requirements that the 

Agency must comply with require us to estimate impacts specific 

to this rule; 2) decisionmakers and the public need to know the 

impacts specific to a particular rule in order to judge the 

merits of the regulation; and 3) estimates specific to a 

particular rule are more transparent than those from a 

cumulative impact analysis. A cumulative impact analysis lumps 

several regulations together and can potentially mask a highcost/low benefit regulation among other rules that may have 

large net benefits. By analyzing each regulation separately, EPA 

makes clear statements about the impacts, costs, and benefits 

that are estimated as a result of this particular regulation. 

This does not, however, mean EPA has failed to incorporate 

these regulations into this analysis. The inclusion of CSAPR and 

other regulatory actions (including federal, state, and local 

actions) in the IPM base case reflects the level of controls 
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that are likely to be in place in response to other requirements 

apart from MATS. This base case provides meaningful projections 

of how the power sector will respond to the cumulative 

regulatory requirements for air emissions, while isolating the 

incremental impacts of MATS. These results are presented in 

Chapter 3 of the RIA.

Additionally, the Agency does reflect on the cumulative 

impacts of our regulations. In March 2011, EPA issued the Second 

Clean Air Act Prospective Report which assessed the benefits and 

costs of regulations pursuant to the 1990 Clean Air Act 

Amendments. The study examines the cumulative impact of these 

regulations (found at 

http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As 

shown in the report, the direct benefits from the 1990 Clean Air 

Act Amendments are estimated to reach almost $2 trillion for the 

year 2020, a figure that dwarfs the direct costs of 

implementation ($65 billion). The full report is at 

http://www.epa.gov/air/sect812/prospective2.html. 

The direct benefits of the 1990 Clean Air Act Amendments and 

associated programs are estimated to significantly exceed their 

direct costs, which means economic welfare and quality of life 

for Americans were improved by passage of the 1990 Amendments. 

The wide margin by which benefits are estimated to exceed costs,
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combined with extensive uncertainty analysis, suggest it is very 

unlikely this result would be reversed using any reasonable 

alternative assumptions or methods. The analysis presented in 

the RIA for the current regulation uses a similar methodology.

The techniques employed by the Agency for generating 

benefits and costs, and consider the most recent and complete 

data available to the Agency. The EPA recognizes that the 

analyses have caveats and limitations, and we discuss our 

analyses and their caveats and limitations in the RIA for the 

rule, as well as in the benefits section of the preamble. The 

Agency has also revised the cost analyses for the final rule to 

reflect data received in public comments on the proposed rule, 

and costs are lower than when the rule was proposed.

k. Impact on state regulators.

Comment: Several commenters expressed concern over the burden 

imposed on state regulatory agencies by the rule. 

Response: The Agency has estimated the costs of implementation 

of the rule to states that own EGUs affected by the rule, and 

has included this analysis in the RIA. The Agency has updated 

this analysis for the final rule and it is included in the RIA. 

While the EPA has not prepared an analysis of the impacts of the 

rule on state programs, the Agency does not believe the rule 

will be unduly burdensome to the state regulatory agencies. The 
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EPA works closely with state regulatory authorities to ensure 

that the rules are implemented properly, and the Agency will 

continue to do so in support of this final rule.

Comment: A commenter states that the reductions in SO2 and PM2.5

required by the proposed rule will assist state and local air 

pollution control agencies to meet health-based air quality 

standards, reduce haze and improve visibility. The commenter

points out that substantial reduction in emissions made by the 

very large sources under the proposed rule will lead to fewer 

pollution controls needed at smaller sources to meet healthbased ambient air requirements. This is a far more costeffective approach than controls at smaller facilities and is 

the lowest cost path to improved public health and a cleaner 

environment.

Response: The EPA acknowledges that the HAP standards in this 

final rule will lead to considerable co-benefit reductions in PM 

and SO2.

l. Miscellaneous.

Comment: A few commenters discussed the impact of the rule on 

the federal budget deficit. One commenter points out that the 

proposed rule will affect the federal budget in two ways:

1. direct compliance costs to electric generating units (EGUs)

owned by federal agencies; and
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2. pass-through compliance costs paid in the form of higher 

prices for electricity purchased by federal agencies.

Response: The Agency estimates the direct compliance costs to 

EGUs that are federally owned as part of the overall cost 

analysis completed for the proposal and disclosed in the RIA for 

the rule. The Agency does not provide an estimate of the impact 

on federal agencies from higher electricity prices associated 

with the rule, however. This type of analysis is not required 

under EO 12866 and statutory requirements.

H. Testing and Monitoring

Comment: Commenters raised numerous issues with the testing and 

monitoring requirements for initial and continuous compliance. 

The following discussion highlights the comments and responses 

to a number of the critical issues and describe where the 

comments have resulted in a significant rule change or where we 

disagreed with commenters’ suggestions of issues or need for 

changes in the rule. Additional comments and responses are 

addressed in the Response to Comments document included in the 

docket for the final rule.

Test Methods. A number of commenters suggested that we 

should allow for the use of Method 5B to determine compliance 

with the PM emission limit. In addition, a number of commenters 

objected to the frequency of stack testing when used as the 
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method for demonstrating continuous compliance. Commenters also 

objected to the requirement for testing one pollutant when the 

source was complying with an optional surrogate (or vice versa); 

for example, commenters objected to testing for HCl if a unit 

was complying with the optional SO2 limit, or testing for metals 

if the unit was complying with the optional PM limit.

Response: Although Method 5B is specified for wet scrubbercontrolled utility boilers under 40 CFR Part 60, subparts D, Da 

and Db, we are excluding Method 5B for demonstrating compliance 

with the filterable PM emissions standard in this final rule. 

The extended high temperature heating of the filters prior to 

weighing as specified in Method 5B would introduce differences 

between the compliance test data and the data that underlie the 

filterable particulate standard. Because the test data that 

underlie and filterable particulate standard are based primarily 

on Method 29 and Method 5 data collected at 320°F or comparable 

filterable particulate methods, we are specifying those same 

methods for determining compliance with the standard. 

For stack test frequency, we modified the final rule to 

require quarterly testing to demonstrate continuous compliance. 

In addition, we agree that testing should be required only for 

the emission limits that your source is complying with, and,

thus, the final rule does not require testing of both the 
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pollutant and the surrogate.

Comment: Fuel Analysis Methods. A number of commenters raised 

various concerns with the fuel analysis methods specified in the 

proposed rule.

Response: Based on the comments received and a further review of 

the technical challenges associated with the proposed fuel 

analysis requirements, we have not finalized the proposed fuel 

analysis requirements. As the rule no longer requires operating 

limits based on fuel content or fuel analysis, the comments on 

this issue are largely moot. For LEEs, we agree that the 

proposed LEE ongoing eligibility requirements were overly 

burdensome and restrictive. As a result, existing solid or 

liquid fired units that qualify for Hg LEE status will be 

required to conduct a 30-day test for Hg using Method 30B each 

year. Neither fuel analysis nor adherence to an operating limit 

will be required. Should an annual test show ineligibility for 

LEE status, the source will revert to the requirements for Hg 

monitoring using CEMS or sorbent traps or, for oil-fired units, 

quarterly emissions testing. Existing solid or liquid fired 

units that qualify for non-mercury LEE status will be required 

to conduct a stack test every 3 years, and neither fuel analysis 

nor adherence to an operating limit will be required. Should the 

stack test show ineligibility for LEE status, the source will 
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revert to using CEMS or PM CPMS or conducting quarterly 

emissions testing.

Comment: Operating Parameter Limits: Some commenters objected to 

the use of enforceable operating parameter limits, requested 

that the rule be more consistent with the compliance assurance 

monitoring program, and raised specific objections to certain 

parameters required for certain control devices. Commenters also 

raised concerns about a PM CEMS operating limit establishing a 

de facto more stringent PM emission limit than the one being 

tested for under the total PM standard in the proposal.

Response: We believe that continuous monitoring in the form of 

CEMS, sorbent trap monitoring systems, and PM CPMS, or frequent 

stack emissions testing are appropriate to ensure ongoing 

compliance with this final rule. We also agree with commenters 

that some of the monitoring provisions in the proposal may have 

been duplicative and unnecessary. In order to provide 

flexibility in the final rule, we have retained a source’s

ability to define an operating limit and to monitor using a PM 

CPMS as an option to periodic filterable PM emissions testing. 

The final rule establishes the PM CPMS as an operating 

limit monitor and not a direct filterable PM emission monitoring 

requirement that meets PS 11 requirements. Although we recognize 

the importance of continued control device performance to ensure 
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emissions minimization, we also are aware that other rules that 

apply to these units including, but not limited to, the 

Operating Permits rule, the Compliance Assurance Monitoring 

rule, the ARP rules, and the NSPS already require continuous 

monitoring in most cases. Those rules will remain in effect so 

the need to impose additional operating limits monitoring or 

CEMS on those units is much reduced.

The final rule also provides for the use of a PM CEMS to 

determine compliance with the filterable PM emission limit if 

the source elects to use this approach. In that case, the PM 

CEMS is used as the direct method of compliance and no 

additional testing is required other than tests that are 

required as part of satisfying the requirements in Performance 

Specification 11 in Appendix B to 40 CFR Part 60 and Procedure 2 

in Appendix F to Part 60. The EPA provided this option in 

response to the comments in order to provide a straightforward 

direct measure of compliance that some sources may want to 

implement.

Comment: Hg CEMS. Commenters raised a number of technical 

concerns about Hg CEMS. Many commenters requested modifications 

so that the requirements would be more consistent with 40 CFR 

Part 75 monitoring requirements. Some commenters questioned the 

ability of the technology to demonstrate compliance with 
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emission limits at very low levels especially for new sources. 

Commenters also opposed high data availability requirements 

given that the technology is new and difficult to operate and 

maintain.

Response: We indicated in the proposed rule the intent to adopt 

CAMR-based requirements for Hg monitoring in place of the 

general 40 CFR Part 63 performance specifications and QA 

requirements. With CAMR, these operating and reporting 

requirements for Hg CEMS went through notice and comment 

rulemaking for the same sources as covered by this final 

rule. Although CAMR was set aside on other grounds, these 

technical specifications and QA requirements reflect significant 

input from stakeholders and analysis by the EPA to establish an 

appropriate foundation for Hg monitoring at electric utilities 

under the CAA. For the final rule, we have made conforming 

changes to ensure that this intent is carried out effectively 

throughout the rule text and Appendix A, as well as including 

certain additional clarifications based on the input received in 

response to the proposed rule. We have also removed a cycle time 

test as unworkable for certain types of Hg CEMS.

The final rule provides the option for use of either Hg 

CEMS or sorbent trap monitoring systems. We believe the record 

clearly shows these to be proven technologies each providing 
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certain advantages. For existing and some of the new unit 

standards, the level of the NIST-traceable Hg gas standards will 

be adequate and consistent with existing applications of Hg 

CEMS. For the lowest limits and other applications where an 

integrated sampling system offers advantages, affected 

facilities may opt to use sorbent trap monitoring systems to 

comply. There are data in the recent draft report entitled 

“Determining the Variability Of CMMS At Low Hg Levels,”

356 that 

demonstrate reasonable performance of at least one Hg CEMS at Hg 

levels below 1.0 microgram per cubic meter (μg/m3) down to 

approximately 0.1 μg/m3. Finally, there is no specific minimum 

data availability requirement for Hg CEMS (or any other CMS 

required under this final rule). This issue is discussed further 

below.

Comment: SO2 CEMS: Although commenters were generally supportive 

of the ability to use SO2 CEMS for units with FGD installed to 

demonstrate compliance with an alternate SO2 emission limit 

instead of the HCl emission limit, there were some concerns with 

aspects of the proposal. Commenters requested that the SO2

monitoring requirements rely on 40 CFR Part 75 given that their 

sources were already meeting those requirements and that this 

rule not establish any new requirements, especially a fourth 

linearity level and the application of 7-day calibration error 

 

356 http://www.icci.org/reports/10Laudal6A-1.pdf
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tests for units with low concentrations (where 40 CFR Part 75

provides an exemption). Commenters were also concerned that the 

rule language only allows the option where the FGD is operated 

“at all times” which seems to imply that the option is not 

allowed if the source ever bypasses the FGD for start-up, 

shutdown, or malfunction reasons. 

Response: After reviewing the comments and assessing the need 

for an additional calibration gas at the emissions limit, we 

have removed this requirement from the final rule while 

retaining the requirement for a linearity check even for SO2

monitors with low span values (≤ 30 ppm). A source can already 

report linearity tests for these units within the context of the 

existing ECMPS reporting without triggering any critical errors. 

This test can be accommodated within the current framework 

without causing issues for 40 CFR Part 75 reporting. The

requirement for a 7-day calibration error test is removed. For 

the “at all times” language, we have clarified this in the final 

rule. The intent is that the FGD be operated during all routine 

boiler operations, and not operated intermittently, seasonally, 

or on some other non-fulltime basis.

Comment: HCl CEMS. In general, commenters argued that HCl CEMS 

do not have an approved performance specification and are not 

widely demonstrated as a proven technology. Those concerns were
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also mentioned for HF CEMS.

Response: We disagree with commenters’ contention that 

continuous HCl monitoring is premature or not available for the 

measurement at the emission limits set in the final rule. HCl 

CEMS are being used on source categories such as municipal waste 

combustors and EGUs. We have reviewed HCl CEMS vendor technology 

claims and found sufficient capability to support this rule 

requirement. We are engaged with representative stakeholders to 

develop a generic performance specification for HCl CEMS 

scheduled for completion in time to be responsive to compliance 

with this rule.

The final rule provides several options for HCl and/or HF 

monitoring including: 

1) Using Fourier Transform Infrared (FTIR)-based HCl CEMS 

and/or HF CEMS complying with Appendix B to the rule which 

relies on PS 15,

2) Seeking approval for an alternative HCl monitoring 

procedure through 40 CFR 63.7(f),

3) Monitoring compliance continuously with the alternate SO2

emission limit at coal-fired or other solid fuel affected

facilities equipped with FGD technology for SO2, and

4) Quarterly reference method testing.

Including these options in the final rule provides 
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flexibility to adopt CEMS monitoring options as the technology 

continues to mature and the new, non-technology-specific EPA

performance specifications becomes available.

Comment: Bypass Stacks. Several commenters raised concerns about 

the technical feasibility of monitoring bypass stacks with a 

CEMS.

Response: We have modified the bypass stack monitoring 

requirements. Under 40 CFR Part 75, we allow the use of a 

maximum potential concentration value for reporting when 

emissions are vented to a bypass stack. That approach works 

within the context of an emissions trading program, but is not 

appropriate when evaluating compliance with a specific emission 

limit. Thus, we have provided two other options. One is to

monitor the bypass stack, consistent with the final rule. The 

other is to treat any hours of bypass stack emissions as periods 

of monitor downtime and hours of deviation from the monitoring 

requirements. Note that a source’s units must continue to meet 

their 30-boiler operating day emissions limits during 

malfunction periods.

Comment: 40 CFR Part 75 Issues. There were a number of general 

comments about the value of relying on 40 CFR Part 75

requirements, including elements such as conditional data 

validation. The commenters generally agreed that the 40 CFR Part 
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75 bias test and bias adjustment factor, and the 40 CFR Part 75

substitute data provisions should not apply. Instead of 

substitute data, many commenters suggested that we needed to 

clarify the valid reasons for monitor downtime and establish an 

appropriate minimum data availability requirement.

Response: We have attempted to harmonize the CEMS requirements 

in this final rule with those under 40 CFR Part 75 wherever

appropriate. One of those examples is the inclusion of 

conditional data validation for Hg CEMS. We disagree that this 

final rule needs a minimum data availability requirement. We 

have not included any specific minimum data availability 

requirement for CEMS or other monitoring in this final rule nor 

do we provide a specific tool for data substitution. We believe 

that there are other provisions in the final rule to provide 

incentives to conduct monitoring in a manner consistent with 

good air pollution control practices and to provide data 

sufficient to demonstrate compliance with a relatively long-term

(30-boiler operating day) emissions rate limit. We agree that 

data quality certainty associated with any calculated value 

decreases with the collection of less data such as would occur 

with extended periods of monitoring system downtime. Even so, we 

believe also that it is necessary and critical for compliance 

with the regulation that a source use all measured data 
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collected during an averaging period to assess compliance 

regardless of any periods of missing data. Sources should not 

disqualify any data otherwise meeting required data quality 

requirements simply because there were data missing for other 

hours or days of the averaging period.

Instead of a minimum data availability threshold that would 

invalidate data collected for some averaging periods because one 

did not collect data for at least a specified percent of an 

averaging time, the final rule requires that a source report as 

deviations to the rule failure to collect data during required 

periods if these deviations are not covered by exceptions 

allowed in the final rule. 

On the issue of applying a data substitution procedure to 

represent actual emissions or pollution control performance, we 

are not requiring data substitutions under this rule. We 

believe, however, that defensibility concerns make it incumbent 

on the source to collect and evaluate other information in 

accordance with 40 CFR section 63.6(f)(3) during periods of 

monitoring downtime to assure compliance with the applicable 

emissions limitations and standards.

We believe that enforcement authorities also can and should 

determine whether a source is meeting any monitoring system 

operating requirements. Should the source or the enforcement 
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authority be concerned about the representativeness of data such 

as during periods of missing data, either one may consider 

collecting information through other means (e.g., supplemental 

emissions testing) to fill data gaps not only because such gaps 

are deviations from the rule but such gaps can lead to 

uncertainty about compliance status.

We further believe that the final rule provides sufficient 

means to ensure CMS performance and ongoing compliance without 

specifying an arbitrary numerical minimum data availability or 

data substitution requirement. We believe that specifying

failure to collect required or otherwise excepted data as a 

deviation from the rule will provide the necessary incentive to 

collect data sufficient to demonstrate compliance with the 

limits in the final rule.

Comment: Recordkeeping. Several commenters opposed the 

requirements related to maintaining records on site and for 5

years.

Response: We believe the recordkeeping and retention 

requirements are consistent with other requirements already in 

place, specifically 40 CFR Part 63.10 (b):

“General recordkeeping requirements. (1) The owner or 

operator of an affected source subject to the 

provisions of this part shall maintain files of all 
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information (including all reports and notifications) 

required by this part recorded in a form suitable and 

readily available for expeditious inspection and 

review. The files shall be retained for at least 5 

years following the date of each occurrence, 

measurement, maintenance, corrective action, report, 

or record. At a minimum, the most recent 2 years of 

data shall be retained on site. The remaining 3 years 

of data may be retained off site. Such files may be 

maintained on microfilm, on a computer, on computer 

floppy disks, on magnetic tape disks, or on 

microfiche.”

In addition, the 5-year retention period is the general 

rule for all recordkeeping for all sources under the Part 70 

operating permits program. Given that the General Provisions for 

40 CFR Part 63 and Part 70 already establish a 5-year retention 

period, we believe it is justified in using those precedents for 

the retention periods under this subpart. If we stayed silent on 

retention period in this subpart, the General Provisions would 

provide for the 5-year retention as would the Part 70 

requirements. Thus, this action does not establish any new 

retention requirements, but merely confirms that the existing 

retention requirements apply. 
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Comment: Electronic Reporting. In the proposed rule, we 

requested comment on using ECMPS for reporting under this rule, 

as well as other options including the ERT. Commenters generally 

supported the use of ECMPS, especially for CEMS data. Some 

commenters requested an additional rulemaking on the specific 

data elements to be collected. There were some concerns raised 

about the ERT given experience during the 2010 ICR process 

during the development of this rule.

Response: We recognize that emissions reporting for continuously 

measured pollutants (SO2, NOX, etc.) and for periodically 

measured pollutants (PM, HAP metals, etc.) have different data 

demands. We recognize that minor revisions of the ECMPS will 

fulfill our data needs for most continuously measured pollutants 

and we will make these modifications for receipt of the 

additional CEMS data. We also recognize the need for substantial 

modifications to the ECMPS to accommodate the data needs for 

periodically measured pollutants and certain CEMS data such as 

PM CEMS data and possibly HAP metals CEMS data. Although major 

modifications of the ECMPS would be required for periodic 

compliance tests by isokinetic and instrumental test methods (as 

well as certain types of CEMS), only minor revisions are 

required of the ERT to receive these tests. We are implementing 

the changes in the ERT that are required to provide the software 
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tools to implement the delivery of these performance test data 

to us.

The electronic submission of compliance test reports to us 

through the Central Data Exchange (CDX) is not solely for the 

purpose of developing improved emissions factors as some 

commenters assert. Although populating WebFIRE will allow us to 

improve emissions factors, we intend to use data stored in 

WebFIRE as the primary location for compliance test reports for 

use by regulatory authorities. The electronic submission of 

compliance test reports is a continuation of our efforts to 

bring the submission and sharing of environmental data into the 

modern age. The storage of this compliance data in our WebFIRE 

provides a convenient location which is already used to store 

source test data.

As federal and state and local agencies’ data systems 

mature, information provided through the ERT will be used to 

populate these data systems. We are currently upgrading the AIRS 

Facility System and expect to replace manually entered 

information with electronic population from the ERT. We are also 

working with several state and local agencies to adopt the use 

of the ERT for delivery of compliance test reports. The ERT is 

also much improved since the version used during the 2010 ICR 

process, and there is no expectation that the information to be 
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reported under this final rule will be as extensive as some of 

the data reported for the 2010 ICR purposes.

We disagree that a separate and independent regulatory 

action is required to implement electronic reporting for 

selected regulated sources. Each of these regulatory actions for 

selected source categories provides ample notice and the 

opportunity for individuals to provide comment. We also disagree 

that the system to receive the compliance data must be 

operational prior to establishing the requirement for regulated 

sources to submit compliance data electronically. We are on 

track to have the capability to receive electronic compliance 

tests through our CDX in sufficient time to receive all utility 

source test reports required by this final rule.

We do plan a separate and independent regulatory action to 

implement electronic reporting for regulated entities which are 

covered by past and future rules. Although we have provided 

draft procedures for the development of emissions factors, that 

effort is an ancillary effort to the electronic delivery of 

compliance test reports. It is our intention to convert to the 

electronic delivery and storage of all air emissions compliance 

source test data. With this transition, we believe this valuable 

information will be more readily available not only for 

compliance purposes but also for a variety of other uses.
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I. Emissions Averaging.

Comment: In response to our request for comments on the 

suitability of emissions averaging and need for a discount 

factor, we received a range of suggestions, including requests 

for clarification regarding eligibility, points for and against 

the need for a discount factor, and suggestions to ease 

implementation.

Response: We are finalizing that owners and operators of 

existing affected sources may demonstrate compliance by 

emissions averaging for EGUs at the affected source that are 

within a single subcategory and that rely on emissions testing 

as the compliance demonstration method. See section VI of thie 

preamble for a fuller discussion.

J. LEE criteria.

Comment: A commenter supported the LEE provisions but believed 

one of the LEE eligibility criteria should set at 29.0 lb/year,

rather than 22.0 lb/year. The commenter suggested 29.0 lb/year 

to be an equally reasonable cut point, especially since that 

value matches the low mass emitter Hg monitoring cutoff in CAMR 

and the low mass emitter Hg monitoring cutoff that several 

states have adopted, including Illinois, 35 Ill. Admin. Code 

section 225.240(a)(4). (See, e.g., Colorado (5 Colo. Code Regs. 

section l 00 l-8, Reg. No.6, Part B, Section VIII.B.l0); 
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Michigan (Mich. Admin. Code R. 336.2160); Montana (Mont. Admin. 

R. 17.8771(12))). Further, a LEE cutoff of 29.0 lb would 

eliminate conflicts and confusion with low mass emitter 

provisions in existing state Hg programs and significantly 

reduce compliance costs and burdens for the additional 

qualifying units without adversely affecting compliance 

assurance with the EGU NESHAP Hg emission limits or materially 

increasing the number of potential qualifying LEEs. Given the 

many other costly burdens that the rule would impose, the 

benefit of LEE to a qualifying unit is not insignificant.

Response: The Agency reviewed the commenter’s suggestions, and 

one of the LEE eligibility criteria in the rule has been revised 

from 22.0 to 29.0 lb of Hg per year. The Agency finds the result 

of consistency with existing state regulations outweighs the two 

percent difference in nationwide Hg mass emissions, from 5 

percent to 7 percent, for LEE eligibility.

VIII. Background Information on the NSPS

A. What is the statutory authority for this final NSPS?

New source performance standards implement CAA section 

111(b), and are issued for categories of sources which cause, or 

contribute significantly to, air pollution which may reasonably 

be anticipated to endanger public health or welfare. Section 111 

of the CAA requires that NSPS reflect the application of the 
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best system of emissions reductions which (taking into 

consideration the cost of achieving such emissions reductions, 

any non-air quality health and environmental impact and energy 

requirements) the Administrator determines has been adequately 

demonstrated. The level of control prescribed by CAA section 111 

historically has been referred to as “Best Demonstrated 

Technology” or BDT. In order to better reflect that CAA section 

111 was amended in 1990 to clarify that “best systems” may or 

may not be “technology,” the EPA is now using the term “best 

system of emission reduction” or BSER. As was done previously in 

analyzing BDT, the EPA uses available information and considers 

the emission reductions and incremental costs for different 

systems available at reasonable cost. Then, the EPA determines 

the appropriate emission limits representative of BSER. Section 

111(b)(1)(B) of the CAA requires EPA to periodically review and 

revise the standards of performance, as necessary, to reflect 

improvements in methods for reducing emissions.

B. What is the regulatory authority for the final rule?

The current standards for steam generating units are 

contained in the NSPS for EGUs (40 CFR Part 60, subpart Da), 

industrial-commercial-institutional steam generating units (40 

CFR Part 60, subpart Db), and small industrial-commercialinstitutional steam generating units (40 CFR Part 60, subpart 
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Dc).

The NSPS for EGUs (40 CFR Part 60, subpart Da) were 

originally promulgated on June 11, 1979 (44 FR 33580) and apply 

to units capable of firing more than 73 megawatts (MW) (250 

MMBtu/h) heat input of fossil fuel that commenced construction, 

reconstruction, or modification after September 18, 1978. The 

NSPS for EGUs also apply to industrial-commercial-institutional 

cogeneration units that sell more than 25 MW and more than onethird of their potential output capacity to any utility power 

distribution system. The most recent significant amendments to 

emission standards under 40 CFR Part 60, subpart Da, were 

promulgated in 2006 (71 FR 9866) resulting in new PM, SO2, and 

NOX limitations for 40 CFR Part 60, subpart Da units.

The NSPS for industrial-commercial-institutional steam 

generating units (40 CFR Part 60, subpart Db) apply to units for 

which construction, modification, or reconstruction commenced 

after June 19, 1984, that have a heat input capacity greater 

than 29 MW (100 MMBtu/h). Those standards were originally 

promulgated on November 25, 1986 (51 FR 42768) and also have 

been amended since the original promulgation to reflect changes 

in BSER for these sources.

The NSPS for small industrial-commercial-institutional 

steam generating units (40 CFR Part 60, subpart Dc) were 
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originally promulgated on September 12, 1990 (55 FR 37674) and 

apply to units with a maximum heat input capacity greater than 

or equal to 2.9 MW (10 MMBtu/h) but less than 29 MW (100 

MMBtu/h). Those standards apply to units that commenced 

construction, reconstruction, or modification after June 9, 

1989.

IX. Summary of the Final NSPS

The final rule amends the emission standards for SO2, NOX, 

and PM in 40 CFR Part 60, subpart Da. Only those units that 

begin construction, modification, or reconstruction after May 3, 

2011, will be affected by the final rule. Compliance with the 

emission limits of the final rule will be determined using 

testing, monitoring, and other compliance provisions similar to 

those set forth in the existing standards. In addition to the 

emissions limits contained in the final rule, we also are 

including several technical clarifications and corrections to 

existing provisions of the subparts.

A. What are the requirements for new EGUs (40 CFR Part 60, 

subpart Da)?

The filterable PM emissions standard for new and 

reconstructed EGUs is 11 nanograms per joule (ng/J) (0.090 pound 

per megawatt hour (lb/MWh)) gross energy output regardless of 

the type of fuel burned. The PM emissions standard for modified 
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EGUs is essentially equivalent to the existing requirements of

13 ng/J (0.015 lb/MWh) heat input regardless of the type of fuel 

burned. Compliance with this emission limit can be determined 

using testing, monitoring, and other compliance provisions

similar to those for PM standards set forth in the existing 

rule. While not required, PM CEMS may be used as an alternative 

method to demonstrate continuous compliance and as an 

alternative to opacity and parameter monitoring requirements.

The SO2 emission limit for new and reconstructed EGUs is 130 

ng/J (1.0 lb/MWh) gross energy output or 97 percent reduction 

regardless of the type of fuel burned with one exception. The 

EPA neither proposed to amended the SO2 standard for coal refusefired EGUs, not reopened the issue of whether coal refuse-fired 

EGUs is an appropriate subcategory, and, therefore, that 

emissions standard is unchanged. The SO2 emission limit for 

modified EGUs burning any fuel is 180 ng/J (1.4 lb/MWh) gross 

energy output or 90 percent reduction. Compliance with the SO2

emission limit is determined on a 30-boiler operating day 

rolling average basis using a CEMS to measure SO2 emissions and 

following the compliance provisions in the proposed rule.

The NOX emission limit for new and reconstructed EGUs is 88 

ng/J (0.70 lb/MWh) gross energy output regardless of the type of 

fuel burned with one exception. The exception is that for new 
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and reconstructed EGUs that burn over 75 percent coal refuse (by 

heat input), the NOX emission limit is 110 ng/J (0.85 lb/MWh) 

gross energy output. The NOX limit for modified EGUs is 140 ng/J 

(1.1 lb/MWh) gross energy output regardless of the type of fuel 

burned in the unit. Compliance with this emission limit is 

determined on a 30-boiler operating day rolling average basis 

using testing, monitoring, and other compliance provisions 

similar to those in the proposed rule.

As an alternative 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

exception is that for new and reconstructed EGUs that burn over 

75 percent coal refuse (by heat input) on an annual basis, the 

NOX/CO emission limit 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).

B. Additional Amendments

See the Response to Comments document.

X. Summary of Significant Changes Since Proposal

A. Emission Limits

The proposal included a combined (filterable plus 

condensable) PM standard. The final standard is based only on 

filterable PM. No standard is being established for condensable 
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PM. The rationale for this is set forth in the Response to 

Comments (RTC) document for this final rule (the NSPS Final Rule 

RTC).

The proposal requested comment on whether the final 

standard should include a stand-alone NOX standard or a combined 

NOX/CO standard. In response to comments we received and our own 

further evaluation of the situation, the final standard includes 

a stand-alone NOX standard and an optional, but not required, 

combined NOX/CO standard as an alternative to the amended NOX

standard. Again, our full rationale for this is set forth in the 

NSPS Final Rule RTC. The proposal also included a request for 

comment on whether the standard should be based on gross or net 

output. In response to comments we received and our own further 

evaluation of the situation, the final standards are based on an 

amended definition of gross output with an optional net outputbased standard. This too is addressed more fully in the NSPS 

Final Rule RTC.

The proposal included alternate emission standards for 

commercial demonstration projects. Proposed commercial 

demonstrations included pressurized fluidized beds, multipollutant control technologies, and advanced combustion 

controls. The final rule includes the commercial demonstration 

permit exemption for pressurized fluidized beds and multi-
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Page 651 of 1103

pollutant control technologies, but not advanced combustion 

controls. Advanced combustion controls are applicable to 

existing facilities and the exemption is not necessary to 

further the development of the technology.

B. Requirements during Startup, Shutdown, and Malfunction

For startup and shutdown, the requirements for PM have 

changed since proposal. For periods of startup and shutdown, the 

EPA is finalizing work practice standards for PM in lieu of 

numeric emission limits. Emissions incurred during periods of 

startup and shutdown for PM are not used in demonstrations of 

compliance with the 30-boiler operating day rolling average 

period applicable for numeric emission standards.

XI. Public Comments and Responses to the Proposed NSPS

See the Response to Comments document.

XII. Impacts of The Final Rule

The EPA anticipates significant public health and 

environmental benefits from the rule as a direct result of the 

substantial reduction in the emissions of several pollutants, 

including SO2, Hg, acid gases and fine particles and metals. For 

example, exposure to Hg can damage the developing nervous 

system, which can impair children's ability to think and learn, 

and fine particles can cause adverse cardiovascular effects. 

Further, reducing Hg deposition to ecosystems will benefit 
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wildlife including fish, birds, and mammals. Fish and fisheating birds, such as the common loon, and mammals suffer 

reproductive, survival, and behavioral impairments due to 

mercury exposure. These effects have also been observed in 

insect-eating and wading birds, including egrets and white ibis. 

Reductions of emissions targeted by this rule also will slow 

acidification and eutrophication of water bodies. 

Additionally, the EPA anticipates significant non-health, 

non-ecological benefits from this rule. The fine particle and SO2

emission reductions achieved by this rule will improve 

visibility, which is especially important for our national 

parks. Emissions reductions from this rule will also avoid an 

estimated $360 million (in $2007) of climate-related costs, such 

as agricultural productivity and property damage from increased 

flood risks.

A. What are the air impacts?

The EPA anticipates significant emission reductions under 

the final rule from coal-fired EGUs, which are of particular 

interest due to their share of total power sector emissions. In 

2015, annual HCl emissions are projected to be reduced by 88 

percent, Hg emissions reduced by 75 percent, and PM2.5 emissions 

reduced by 19 percent from coal-fired EGUs greater than 25 MW. 

In addition, the EPA projects SO2 emission reductions of 41 
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percent, and annual CO2 reductions of 1 percent from coal-fired 

EGUs greater than 25 MW by 2015, relative to the base case. See

Table 7.

TABLE 7. SUMMARY OF EMISSION REDUCTIONS FROM COAL-FIRED EGUS 

GREATER THAN 25 MW (TPY)

SO2

(millio

n tons)

NOX

(millio

n tons)

Mercury

(tons)

HCl

(thousa

nd 

tons)

PM2.5

(thousa

nd 

tons)

CO2

(million 

metric 

tonnes)

Base 

Case 3.3 1.7 27 45 270 1,906

MATS 1.9 1.7 7 6 218 1,882

Change -1.4 0.0 -20 -40 -52 -23

Note: Numbers may not add due to rounding.

The reductions in this table do not account for reductions 

in other HAP which will occur as a result of this rule. For 

instance, the fine particulate reductions presented above only 

partly reflect reductions in many heavy metal particulates, and 

the HCl reductions above only partly reflect reductions of all 

acid gases. This rule will also result in additional HAP 

reductions from oil-fired EGUs, which are covered by the rule 

but are not included in the EPA’s analysis of emission 

reductions.

B. What are the energy impacts?

The EPA projects that approximately 4.7 GW of coal-fired 

generation (less than 2 percent of all coal-fired capacity and 

0.5 percent of total generation capacity in 2015) may be 
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uneconomic to maintain and may be removed from operation by 

2015. These units are predominantly smaller, less frequently 

used, and are dispersed throughout the country. If current 

forecasts of either natural gas prices or electricity demand 

were revised in the future to be higher, that would create a 

greater incentive to make further investments in these 

facilities and keep these units operational.

The final rule has other important energy market 

implications. Average nationwide retail electricity prices are 

projected to increase in the contiguous U.S. by 3.1 percent in 

2015. The average delivered coal price is projected to increase 

by less than 2 percent in 2015 as a result of shifts within and 

across coal types. The EPA also projects that electric power 

sector-delivered natural gas prices will increase by between 0.3 

and 0.6 percent over the 2015 to 2030 timeframe, on average, and 

that natural gas use for electricity generation will increase by 

less than 200 billion cubic feet (BCF) in 2015. These impacts 

are well within the range of price variability that is regularly 

experienced in natural gas markets. Finally, the EPA projects 

coal production for use by the power sector, a large component 

of total coal production, will decrease by 10 million tons in 

2015 from base case levels, which is about 1 percent of total 

coal produced for the electric power sector in that year.
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C. What are the cost impacts?

The power industry’s “compliance costs” are represented in 

this analysis as the change in electric power generation costs 

between the base case and policy case in which the sector 

pursues pollution control approaches to meet the MATS emission 

standards. In simple terms, these costs are the resource costs 

of direct power industry expenditures to comply with the EPA’s 

requirements.

The EPA projects that the annual incremental compliance 

cost of MATS is $9.6 billion in 2015 ($2007). The annualized 

incremental cost is the projected additional cost of complying 

with the rule in the year analyzed, and includes the amortized 

cost of capital investment and the ongoing costs of operating 

additional pollution controls, needed new capacity, shifts 

between or amongst various fuels, and other actions associated 

with compliance.

The total incremental compliance cost includes compliance 

costs modeled in IPM of $9.4 billion, costs modeled outside of 

IPM for oil-fired EGUs of $56 million, and monitoring, 

reporting, and recordkeeping costs of $158 million.

D. What are the economic impacts?

For this final rule, EPA analyzed the costs using the IPM. 

The IPM is a dynamic linear programming model that can be used 
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to examine the economic impacts of air pollution control 

policies for a variety of HAP and other pollutants throughout 

the contiguous U.S. for the entire power system.

Documentation for IPM can be found in the docket for this 

rulemaking or at http://www.epa.gov/airmarkets/progsregs/epaipm/index.html.

The EPA performed a screening analysis for impacts on small 

entities by comparing compliance costs to sales/revenues (e.g., 

sales and revenue tests). The EPA’s analysis can be found in 

Chapter 7 of the RIA for this rule. The EPA has also prepared a 

Final Regulatory Flexibility Analysis (FRFA) that discusses 

alternative regulatory or policy options that minimize the 

rule’s small entity impacts. 

Although a stand-alone analysis of employment impacts is 

not included in a standard cost-benefit analysis, the current 

economic climate has led to heightened concerns about potential 

job impacts. Executive Order 13563 specifically states that our 

“regulatory system must protect public health, welfare, safety, 

and our environment while promoting economic growth, innovation, 

competitiveness, and job creation” (emphasis added). 

Under conditions of full employment, it is conventional to 

assume that regulations will merely shift jobs from one sector 

to another, without having a material effect on employment 
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levels. Potential employment effects are of greater concern in 

the current economic climate, with high levels of employment, 

because of the risk that displaced workers may not find 

alternative jobs. In addition, regulations that result in firms 

hiring workers, in order to ensure compliance, may have a 

positive effect on employment. 

During sustained periods of excess unemployment, the 

opportunity cost of labor required by regulated sectors to bring 

their facilities into compliance with an environmental 

regulation may be lower than it would be during a period of full 

employment (particularly if regulated industries employ 

otherwise idled labor to design, fabricate, or install the 

pollution control equipment required under this final rule). 

Consistent with EO 13563, the EPA includes estimates of job 

impacts associated with the final rule. In the electricity 

sector, the EPA estimates that the net employment effect will 

range from −15,000 to +30,000 jobs, with a central estimate of 

+8,000. The EPA also presents an estimate of short-term 

employment effects as a result of increased demand for pollution 

control equipment. 

The results of this analysis, found in Chapter 6 of the 

RIA, indicate that the final rule has the potential to provide 

increases in short-term employment in the environmental 
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industry, primarily driven by the high demand for new pollution 

control equipment. Overall, the results suggest that the final 

rule could support a net of roughly 46,000 job years357 in direct 

employment impacts in 2015.

There are other employment effects that cannot be estimated 

quantitatively at this time. The employment gains related to the 

new pollution controls are likely to be tempered by some losses 

due to certain coal retirements. On the other hand, some of 

those workers who lose their jobs due to plant retirements could 

find alternative employment operating the replacement 

electricity generating equipment or new pollution controls at 

nearby units. Finally, job losses due to reduced coal demand may

be offset by job gains due to increased natural gas demand, 

potentially resulting in a positive net change in employment due 

to fuel demand changes.

The basic approach to estimate these employment impacts 

involved using IPM projections from the final rule analysis, in 

particular the amount of existing coal-fired capacity that is 

projected to be retrofit with pollution control technologies. 

These data, along with data on labor and resource needs of new 

 

357 Numbers of job years are not the same as numbers of 

individual jobs, but represents the amount of work that can be 

performed by the equivalent of one full-time individual for a 

year (or FTE). For example, 25 job years may be equivalent to 

five full-time workers for five years, 25 full-time workers for 

one year, or one full-time worker for 25 years.
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pollution controls and labor productivity from engineering 

studies and secondary sources, are used to estimate employment 

impacts for the pollution control industry in 2015. For more 

information, please refer to Chapter 6 and appendix 6B in the 

RIA.

The EPA relied on Morgenstern, et al. (2002), to identify 

three economic mechanisms by which pollution abatement 

activities can influence jobs in the regulated sector separately 

from the short-term employment effects:

 higher production costs raise market prices, higher prices 

reduce consumption, and employment within an industry falls 

(“demand effect”);

 pollution abatement activities require additional labor 

services to produce the same level of output (“cost 

effect”); and

 post-regulation production technologies may be more or less 

labor intensive (i.e., more/less labor is required per 

dollar of output) (“factor-shift effect”).

Using plant-level Census information between the years 1979 

and 1991, Morgenstern, et al., estimate the size of each effect 

for four polluting and regulated industries (petroleum, plastic 

material, pulp and paper, and steel). On average across the four 

industries, each additional $1 million spent on pollution 
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abatement results in a small net increase of 1.55 jobs; the 

estimated effect is not a statistically different from zero. As 

a result, the authors conclude that increases in pollution 

abatement expenditures may increase employment in the relevant 

sectors and do not necessarily cause economically significant 

employment changes. The conclusion is similar to that of Berman 

and Bui (2001) who found that increased air quality regulation 

in Los Angeles did not cause large employment changes.358 For 

more information, please refer to Chapter 6 of the RIA for this 

final rule.359

In the directly affected sector, the EPA estimates that the 

net employment effect will range from −15,000 to +30,000 jobs, 

with a central estimate of +8,000. The ranges of job effects for 

the electricity sector, as calculated using the Morgenstern, et 

al., approach are listed in Table 8.

TABLE 8. RANGE OF JOB EFFECTS FOR THE ELECTRICITY SECTOR

Estimates using Morgenstern, et al. (2001) 

Demand 

Effect

Cost 

Effect

Factor Shift 

Effect

Net 

Effect

Change in 

Full-Time Jobs 

per Million 

−3.56 2.42 2.68 1.55

 

358 For alternative views in economic journals, see Henderson 

(1996) and Greenstone (2002).

359 It should be noted that if more labor must be used to produce 

a given amount of output, then this implies a decrease in labor 

productivity. A decrease in labor productivity will cause a 

short-run aggregate supply curve to shift to the left, and 

businesses will produce less, all other things being equal.
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Dollars of 

Environmental 

Expenditurea

Standard Error 2.03 0.83 1.35 2.24

EPA estimate 

for Final 

Ruleb

-39,000 to 

+2,000 

+4,000 to 

+21,000

+200 to 

+27,000

-15,000 to 

+30,000

a Expressed in 1987 dollars. See footnote a from Table 6-2 of the 

RIA for inflation adjustment factor used in the analysis.

b According to the 2007 Economic Census, the electric power 

generation, transmission and distribution sector (NAICS 2211) 

had approximately 510,000 paid employees.

The EPA recognizes there may be other job effects that are 

not considered in the Morgenstern, et al., study. Although EPA 

has considered some economy-wide changes, we do not have 

sufficient information to quantify other job effects associated 

with this rule.

E. What are the benefits of this final rule?

1. Benefits of Reducing HAP Emissions

a. Human Health and Environmental Effects Due to Exposure to 

MeHg. In this section, we provide a qualitative description of 

human health and environmental effects due to exposure to MeHg. 

The NAS Study (NRC, 2000) provides a thorough review of the 

effects of MeHg on human health. Many of the peer-reviewed 

articles cited in this section are publications originally cited 

in the NAS Study. In addition, the EPA has conducted literature 

searches to obtain other related and more recent publications to 

complement the material summarized by the NAS in 2000.

b. Neurologic Effects of Exposure to MeHg. In its review of the 
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literature, the NAS found neurodevelopmental effects to be the 

most sensitive and best documented endpoints and concluded that 

they are appropriate for establishing an RfD (NRC, 2000); in 

particular NAS supported the use of results from neurobehavioral 

or neuropsychological tests. The NAS Study (NRC, 2000) noted 

that studies in animals reported sensory effects as well as 

effects on brain development and memory functions and support 

the conclusions based on epidemiology studies. The NAS noted 

that their recommended neurodevelopmental endpoints for an RfD 

are associated with the ability of children to learn and to 

succeed in school. They concluded the following: “The population 

at highest risk is the children of women who consumed large 

amounts of fish and seafood during pregnancy. The committee 

concludes that the risk to that population is likely to be 

sufficient to result in an increase in the number of children 

who have to struggle to keep up in school.”

c. Cardiovascular Impacts of Exposure to MeHg. The NAS 

summarized data on cardiovascular effects available up to 2000. 

Based on these and other studies, the NAS Study concluded that 

“Although the data base is not as extensive for cardiovascular 

effects as it is for other end points (i.e., neurologic effects) 

the cardiovascular system appears to be a target for MeHg 

toxicity in humans and animals.” The report also stated that 
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“additional studies are needed to better characterize the effect 

of MeHg exposure on blood pressure and cardiovascular function 

at various stages of life.”

Additional cardiovascular studies have been published since 

2000. The EPA did not develop a quantitative dose-response 

assessment for cardiovascular effects associated with MeHg 

exposures, as there is no consensus among scientists on the 

dose-response functions for these effects. In addition, there is 

inconsistency among available studies as to the association 

between MeHg exposure and various cardiovascular system effects. 

The pharmacokinetics of some of the exposure measures (such as 

toenail Hg levels) are not well understood. The studies have not 

yet received the review and scrutiny of the more wellestablished neurotoxicity data base.

d. Genotoxic Effects of Exposure to MeHg. The Mercury Study 

noted that MeHg is not a potent mutagen but is capable of 

causing chromosomal damage in a number of experimental systems. 

The NAS Study indicated that evidence that human exposure to 

MeHg causes genetic damage is inconclusive; they note that some 

earlier studies showing chromosomal damage in lymphocytes may 

not have controlled sufficiently for potential confounders. One 

study of adults living in the Tapajós River region in Brazil 

(Amorim et al., 2000) reported a direct relationship between 
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MeHg concentration in hair and DNA damage in lymphocytes, as 

well as effects on chromosomes. Long-term MeHg exposures in this 

population were believed to occur through consumption of fish, 

suggesting that genotoxic effects (largely chromosomal 

aberrations) may result from dietary, chronic MeHg exposures 

similar to and above those seen in the populations studied in 

the Faroe Islands and Republic of Seychelles.

e. Immunotoxic Effects to Exposure to MeHg. Although exposure to 

some forms of Hg can result in a decrease in immune activity or 

an autoimmune response (ATSDR, 1999), evidence for immunotoxic 

effects of MeHg is limited (NRC, 2000).

f. Other Hg-Related Human Toxicity Data. Based on limited human 

and animal data, MeHg is classified as a “possible” human 

carcinogen by the International Agency for Research on Cancer 

(IARC, 1994) and in IRIS (USEPA, 2002). The existing evidence 

supporting the possibility of carcinogenic effects in humans 

from low-dose chronic exposures is tenuous. Multiple human 

epidemiological studies have found no significant association 

between Hg exposure and overall cancer incidence, although a few 

studies have shown an association between Hg exposure and 

specific types of cancer incidence (e.g., acute leukemia and 

liver cancer) (NAS, 2000).

Some evidence of reproductive and renal toxicity in humans 
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Page 665 of 1103

from MeHg exposure exists. However, overall, human data 

regarding reproductive, renal, and hematological toxicity from 

MeHg are very limited and are based on studies of the two highdose poisoning episodes in Iraq and Japan or animal data, rather 

than epidemiological studies of chronic exposures at the levels 

of interest in this analysis.

g. Ecological Effects of Hg. Deposition of Hg to watersheds can 

also have an impact on ecosystems and wildlife. Mercury 

contamination is present in all environmental media, with 

aquatic systems experiencing the greatest exposures due to 

bioaccumulation. Bioaccumulation refers to the net uptake of a 

contaminant from all possible pathways and includes the 

accumulation that may occur by direct exposure to contaminated 

media as well as uptake from food.

A review of the literature on effects of Hg on fish360

reports results for numerous species including trout, bass 

(large and smallmouth), northern pike, carp, walleye, salmon, 

and others from laboratory and field studies. The effects of 

MeHg in fish are reproductive in nature. Although we cannot 

determine at this time whether these reproductive deficits are 

affecting fish populations across the U.S. it should be noted 

that it would seem reasonable that over time reproductive 

 

360 Crump, KL, and Trudeau, VL. Mercury-induced reproductive 

impairment in fish. Environmental Toxicology and Chemistry. Vol. 

28, No. 5, 2009.
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deficits would have an effect on populations.

Mercury also affects avian species. In previous reports361

much of the focus has been on large piscivorous species, in 

particular the common loon. According to Evers, et al., 

significant adverse effects from Hg on breeding loons have been 

found to occur, including behavioral (reduced nest-sitting), 

physiological (flight feather asymmetry) and reproductive 

(chicks fledged/territorial pair) effects and reduced 

survival.362 Additionally, Evers, et al. (see footnote 5), 

believe that the weight of evidence indicates that populationlevel effects occur in parts of Maine and New Hampshire, and 

potentially in broad areas of the loon’s range.

Recently, attention has turned to other piscivorous species 

such as the white ibis and great snowy egret. These wading birds 

have a very wide diet including crayfish, crabs, snails, insects 

 

361 U.S. Environmental Protection Agency (EPA). 1997. Mercury 

Study Report to Congress. Volume V: Health Effects of Mercury 

and Mercury Compounds. EPA-452/R-97-007. U.S. EPA Office of Air 

Quality Planning and Standards, and Office of Research and 

Development; U.S. Environmental Protection Agency (U.S. EPA). 

2005. Regulatory Impact Analysis of the Final Clean Air Mercury 

Rule. Research Triangle Park, NC., March; EPA report no. EPA452/R-05-003. Available on the Internet at 

<http://www.epa.gov/ttn/ecas/regdata/RIAs/mercury_ria_final.pdf

362 Evers, DC, Savoy, LJ, DeSorbo, CR, Yates, DE, Hanson, W, 

Taylor, KM, Siegel, LS, Cooley, JH, Jr., Bank, MS, Major, A, 

Munney, K, Mower, BF, Vogel, HS, Schoch, N, Pokras, M, Goodale, 

MW, Fair, J. Adverse effects from environmental mercury loads on 

breeding common loons. Ecotoxicology. 17:69-81, 2008; Mitro, MG, 

Evers, DC, Meyer, MW, and Piper, WH. Common loon survival rates 

and mercury in New England and Wisconsin. Journal of Wildlife 

Management. 72(3): 665-673, 2008.
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and frogs. White ibis have been observed to have decreased 

foraging efficiency363 and have been shown to exhibit decreased 

reproductive success and altered pair behavior.364 In egrets, Hg 

has been implicated in the decline of the species in south 

Florida,

365 and Hoffman366 has shown that egrets exhibit liver and 

possibly kidney effects. Although ibises and egrets are most 

abundant in coastal areas and these studies were conducted in 

south Florida and Nevada, the ranges of ibises and egrets extend 

to a large portion of the U.S.

Insectivorous birds have also been shown to suffer adverse 

effects due to Hg exposure. Songbirds such as Bicknell’s thrush, 

tree swallows, and the great tit have shown reduced 

reproduction, survival, and changes in singing behavior. Exposed 

 

363 Adams, EM, and Frederick, PC. Effects of methylmercury and 

spatial complexity on foraging behavior and foraging efficiency 

in juvenile white ibises (Eudocimus albus). Environmental 

Toxicology and Chemistry. Vol 27, No. 8, 2008.

364 Frederick, P, and Jayasena, N. Altered pairing behavior and 

reproductive success in white ibises exposed to environmentally 

relevant concentrations of methylmercury. Proceedings of The 

Royal Society B. doi: 10-1098, 2010.

365 Sepulveda, MS, Frederick, PC, Spalding, MG, and Williams, GE, 

Jr. Mercury contamination in free-ranging great egret nestlings 

(Ardea albus) from southern Florida, USA. Environmental 

Toxicology and Chemistry. Vol. 18, No.5, 1999.

366 Hoffman, DJ, Henny, CJ, Hill, EF, Grover, RA, Kaiser, JL, 

Stebbins, KR. Mercury and drought along the lower Carson River, 

Nevada: III. Effects on blood and organ biochemistry and 

histopathology of snowy egrets and black-crowned night-herons on 

Lahontan Reservoir, 2002-2006. Journal of Toxicology and 

Environmental Health, Part A. 72: 20, 1223-1241, 2009.
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tree swallows produced fewer fledglings,367 had lower survival

rates,

368 and had compromised immune competence.369 The great tit 

has exhibited reduced singing behavior and smaller song 

repertoire in areas of high contamination.370

In mammals, adverse effects have been observed in mink and 

river otter, both fish eating species. For otter from Maine and 

Vermont, maximum concentrations of Hg in fur nearly equal or 

exceed a level associated with mortality and concentration in 

liver for mink in Massachusetts/Connecticut and the levels in 

fur from mink in Maine exceed concentrations associated with 

acute mortality.371 Adverse sublethal effects may be associated 

with lower Hg concentrations and consequently may be more 

widespread than potential acute effects. These effects may 

include increased activity, poorer maze performance, abnormal 

 

367 Brasso, RL, and Cristol, DA. Effects of mercury exposure in 

the reproductive success of tree swallows (Tachycineta bicolor). 

Ecotoxicology. 17:133-141, 2008.

368 Hallinger, KK, Cornell, KL, Brasso, RL, and Cristol, DA. 

Mercury exposure and survival in free-living tree swallows 

(Tachycineta bicolor). Ecotoxicology. Doi: 10.1007/s10646-010-

0554-4, 2010.

369 Hawley, DM, Hallinger, KK, Cristol, DA. Compromised immune 

competence in free-living tree swallows exposed to mercury. 

Ecotoxicology. 18:499-503, 2009.

370 Gorissen, L, Snoeijs, T, Van Duyse, E, and Eens, M. Heavy 

metal pollution affects dawn singing behavior in a small 

passerine bird. Oecologia. 145: 540-509, 2005.

371 Yates, DE, Mayack, DT, Munney, K, Evers DC, Major, A, Kaur, 

T, and Taylor, RJ. Mercury levels in mink (Mustela vison) and 

river otter (Lonra canadensis) from northeastern North America. 

Ecotoxicology. 14, 263-274, 2005.
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startle reflex, and impaired escape and avoidance behavior.372

h. Methodology for Partial Hg Benefits Estimation. The EPA has 

conducted a national-scale analysis of the benefits to 

recreational anglers of avoided IQ loss related to reductions of 

Hg emissions and subsequent deposition that will be achieved by 

this rule. Because the primary measurable health effect of 

concern — developmental neurological abnormalities in children —

occurs as a result of in-utero exposures to Hg, the specific 

population of interest in this case is prenatally exposed 

children. To identify and estimate the size of this exposed 

population, the benefits analysis focused on pregnant women in 

freshwater recreational angler households. Estimating Hg 

exposures for this exposure pathway and population of interest 

requires three main components: 1) the size of the exposed 

population of interest (annual number of pregnant women in 

freshwater angler households during the year), 2) the average 

concentration of MeHg in noncommercial freshwater fish filets 

consumed, and 3) the average daily consumption rate of 

noncommercial freshwater fish. The Hg concentrations of fish in 

the waterbodies where the fish are caught are modeled using 

Mercury Maps to project the decline in concentrations due to the 

rule. To approximate the percentage of freshwater fishing trips 

 

372 Scheuhammer, AM, Meyer MW, Sandheinrich, MB, and Murray, MW. 

Effects of environmental methylmercury on the health of wild 

birds, mammals, and fish. Ambio. Vol.36, No.1, 2007.
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(and exposed individuals) from each Census tract matched to each 

waterbody type, the EPA used state-level averages. These 

averages were calculated for each state, based on the portion of 

residents’ freshwater fishing trips that are to each waterbody 

type, based on 2001 National Survey of Fishing, Hunting, and 

Wildlife-Associated Recreation (FHWAR) data.

Data from the 1994 National Survey on Recreation and the 

Environment (NSRE) were used to approximate the percentage of 

freshwater fishing trips (and exposed individuals) matched to 

different distances from anglers’ residential location.

To determine an appropriate daily fish consumption rate for 

the analysis, the EPA conducted an extensive review of existing 

literature characterizing self-caught freshwater fish 

consumption. Based on this review, it was decided that the 

ingestion rates for recreational freshwater fishers, specified 

as “recommended” in the EPA’s “Environmental Exposure Factors 

Handbook” (EPA, 1997), represented the most appropriate values 

to use in this analysis.

Estimating the IQ decrements in children that result from 

mothers’ prenatal ingestion of Hg from fish required two steps. 

First, based on the estimated average daily maternal ingestion 

rate, the expected Hg concentration in the hair of exposed 

pregnant women was estimated. Second, to estimate the expected 
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IQ decrement in offspring, the following dose-response 

relationship was developed based on the summary findings 

reported in Axelrad et al. (2007).

The valuation approach used to assess monetary losses due 

to IQ decrements is based on an approach applied in previous EPA 

analyses (EPA, 2008). The approach expresses the potential loss 

to an affected individual resulting from IQ decrements in terms 

of foregone future earnings (net of changes in education costs) 

for that individual.

The estimate for “Present Value of Lifetime Earnings” is 

derived using earnings and labor force participation rate data 

from the Bureau of Labor Statistics 2006 Current Population 

Survey. Estimates of the average effect of a 1-point increase in 

IQ on lifetime earnings range from a 1.76 percent increase 

(Schwartz, 1994) to a 2.379 percent increase (Salkever, 1995). 

The percentage increases in the two studies reflect both the 

direct impact of IQ on hourly wages and indirect effects on 

annual earnings as the result of additional schooling and 

increased labor force participation. The estimate for years of 

additional schooling is based on Schwartz (1994), who reports an 

increase of 0.131 years of schooling per IQ point.

In addition to this positive net effect on earnings, an 

increase in IQ is also assumed to have a positive effect on the 
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amount of time spent in school and on associated costs. To 

incorporate (1) uncertainty regarding the size of the percentage 

change in future earnings and (2) different assumptions 

regarding the discount rate, the resulting value estimates for 

the average net loss per IQ point decrement are expressed as a 

range. Assuming a 3 percent discount rate, value IQ ranges from 

$8,013 (using the Schwartz estimates) to $11,859 (using the 

Salkever estimates) in increased earnings per year per 1-point 

IQ increase. With a 7 percent discount rate assumption, the 

value IQ estimates range from $893 to $1,958 in increased 

earnings per year per 1-point IQ increase.

The EPA analyzed the aggregate national IQ and presentvalue loss estimates for two base case and three emission 

control scenarios. The highest losses are estimated for the 2005 

base case. For the population of prenatally exposed children 

included in the analysis (almost 240,000), Hg exposures under 

baseline conditions during the year 2005 are estimated to have 

resulted in more than 25,500 IQ points lost. Assuming a 3 

percent discount rate, the present-year value of these losses 

ranges from $204.8 million to $292.5 million nationally.

373 These 

 

373 Monetized benefits estimates are for an immediate change in 

MeHg levels in fish. If a lag in the response of MeHg levels in 

fish were assumed, the monetized benefits could be significantly 

lower, depending on the length of the lag and the discount rate 

used. As noted in the discussion of the Mercury Maps modeling, 

the relationship between deposition and fish tissue MeHg is 
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losses represent expected present value of declines in future 

net earnings over the entire lifetimes of the children who are 

prenatally exposed during the year 2005. With a 7 percent 

discount rate, the present-year value range is considerably 

lower: $22.8 million to $50.0 million.

For this rule, the EPA generated estimates of aggregate 

nationwide benefits associated with reductions in Hg exposures 

and resulting reductions in IQ losses. Most importantly, the 

benefits of the 2016 MATS scenario (relative to the 2016 base 

case) are estimated to range between $4 million and $6 million 

(assuming a 3 percent discount rate), because of an estimated 

511 point reduction in IQ losses. The EPA recognizes that these 

calculated benefits are a small subset of the benefits of 

reducing Hg emissions.

2. Health and Welfare Co-Benefits

Emission controls installed to meet the requirements of 

this rule will generate co-benefits by reducing criteria 

pollutants including PM2.5 and SO2, as well as CO2. For this rule, 

we were only able to estimate the mortality benefits of PM2.5

reductions due to changes in emissions of SO2 and direct PM2.5 and 

climate benefits resulting from CO2 reductions. Additional cobenefits may result from decreases in PM2.5 morbidity impacts, 

 

proportional in equilibrium, but the Mercury Maps approach does 

not provide any information on the time lag of response.
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decreases in sulfur deposition and direct health effects of SO2,

and improvements in visibility in national parks and wilderness 

areas. Total co-benefits may be higher than the partial 

estimates of co-benefits provided here. Our best estimate of the 

monetized health and climate co-benefits of this rule in 2016 at 

a 3 percent discount rate are $37 billion to $90 billion or $33 

billion to $81 billion at a 7 percent discount rate (2007$). 

Using alternate relationships between PM2.5 and premature 

mortality supplied by experts, higher and lower health cobenefits estimates are plausible, but most of the expert-based 

estimates fall between these two estimates.374

a. Human Health Co-Benefits. To estimate the human health cobenefits of this rule, the EPA used benefit-per-ton factors to 

quantify the changes in PM2.5-related health impacts and 

monetized benefits based on changes in SO2 and direct PM2.5 

emissions. These benefit-per-ton factors were based on an 

interim baseline and policy scenario for which full-scale 

ambient air quality modeling and air quality-based human health 

benefits assessments were performed. This general approach and 

methodology is laid out in Fann, et al. (2009),375 but for this 

 

374 Roman, et al, 2008. Expert Judgment Assessment of the 

Mortality Impact of Changes in Ambient Fine Particulate Matter 

in the U.S. Environ. Sci. Technol., 42, 7, 2268–2274.

375 Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. “The influence of 

location, source, and emission type in estimates of the human 

health benefits of reducing a ton of air pollution.” Air Qual 
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rule the air quality modeling used a better spatial 

representation of the emission changes from EGUs. Using a 

benefit-per-ton approach adds another important source of 

uncertainty to the benefits estimates. For more details on the 

creation of the benefit-per-ton factors and their application to 

emission reductions under this rule, please refer to the RIA for 

this rule in the docket.

Table 9 presents the estimates of reduced annual incidence 

of PM2.5-related health effects in 2016 resulting from this rule. 

Table 10 presents the estimated annual monetary value of the 

reduced incidence of quantified health endpoints in 2016 

resulting from this rule. 

The reduction in premature fatalities each year accounts 

for between 93 and 97 percent of the estimated health cobenefits that were monetized.

TABLE 9. ESTIMATED REDUCTIONS IN INCIDENCE OF PM2.5-RELATED 

HEALTH EFFECTS IN 2016a

Health Effect Number of Reduced Cases

Adult Premature Mortality

Pope et al. (2002) (age >30) 4,200

(1,200 to 7,200)

Laden et al. (2006) (age >25)

11,000

(5,000 to 17,000)

Infant Premature Mortality 

(< 1 year)

20

(-22 to 61)

 

Atmos Health (2009) 2:169–176.
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Chronic Bronchitis 2,800

(88 to 5,600)

Non-fatal heart attacks 

(age > 18)

4,700

(1,200 to 8,300)

Hospital admissions—respiratory 

(all ages)

830

(330 to 1,300)

Hospital admissions—cardiovascular 

(age > 18)

1,800

(1,200 to 2,200)

Emergency room visits for asthma 

(age < 18)

3,100

(1,600 to 4,700)

Acute bronchitis 

(age 8-12)

6,300

(-1,400 to 14,000)

Lower respiratory symptoms 

(age 7-14)

80,000

(31,000 to 130,000)

Upper respiratory symptoms 

(asthmatics age 9-11)

60,000

(11,000 to 110,000)

Asthma exacerbation 

(asthmatics 6-18)

130,000

(4,500 to 450,000)

Lost work days 

(ages 18-65)

540,000

(460,000 to 620,000)

Minor restricted-activity days 

(ages 18-65)

3,200,000

(2,600,000 to 3,800,000)

a Values rounded to two significant figures. Co-benefits from 

reducing exposure to ozone, other criteria pollutants, and HAP, 

as well as reducing visibility impairment and ecosystem effects 

are not included here.

TABLE 10. ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-

RELATED HEALTH BENEFITS IN 2016a

Health Effect Monetized Benefits

Adult Premature Mortality

Pope, et al. (2002) (age >30)

3% discount rate $34
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($2.6 to $100)

7% discount rate $30

($2.4 to $92)

Laden, et al. (2006) (age >25)

3% discount rate $87

($7.5 to $250)

7% discount rate $78

($6.8 to $230)

Infant Premature Mortality 

(< 1 year)

$0.2

($-0.2 to $0.8)

Chronic Bronchitis $1.4

($0.1 to $6.4)

Non-fatal heart attacks (age >18)

3% discount rate $0.5

($0.1 to $1.3)

7% discount rate $0.4

($0.1 to $1.0)

Hospital admissions—respiratory (all 

ages)

$0.01

($0.01 to $0.02)

Hospital admissions—cardiovascular 

(age > 18)

$0.03

(<$0.01 to $0.05)

Emergency room visits for asthma 

(age < 18) <$0.01

Acute bronchitis (age 8-12) <$0.01

Lower respiratory symptoms 

(age 7-14) <$0.01

Upper respiratory symptoms 

(asthmatics age 9-11) <$0.01

Asthma exacerbation 

(asthmatics 6-18) <$0.01

Lost work days (ages 18-65) $0.1

($0.1 to $0.1)

Minor restricted-activity days (ages 

18-65)

$0.2

($0.1 to $0.3)

Monetized Health Co-Benefits

Pope, et al. (2002)

3% discount rate $36

($2.8 - $110)

7% discount rate $33

($2.5 - $100)

Laden, et al. (2006)

3% discount rate $89

($7.7 - $260)

7% discount rate $80

($6.9 - $240)
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a Values rounded to two significant figures. Co-benefits from 

reducing exposure to ozone, other criteria pollutants, and HAP, 

as well as reducing visibility impairment and ecosystem effects 

are not included here.

It is important to note that the magnitude of the PM2.5 cobenefits is largely driven by the concentration response 

function for premature mortality. Experts have advised the EPA 

to consider a variety of assumptions, including estimates based 

both on empirical (epidemiological) studies and judgments 

elicited from scientific experts, to characterize the 

uncertainty in the relationship between PM2.5 concentrations and 

premature mortality. We cite two key empirical studies, one 

based on the American Cancer Society cohort study376 and the 

other based on the extended Six Cities cohort study.377 The 

analyses upon which this rule is based were selected from the 

peer-reviewed scientific literature. We used up-to-date 

assessment tools, and we believe the results are highly useful 

in assessing this rule.

Every benefit analysis examining the potential effects of a 

change in environmental protection requirements is limited to 

some extent by data gaps, model capabilities (such as geographic 

coverage), and uncertainties in the underlying scientific and 

 

376 Pope et al., 2002. “Lung Cancer, Cardiopulmonary Mortality, 

and Long-term Exposure to Fine Particulate Air Pollution.” 

Journal of the American Medical Association. 287:1132–1141.

377 Laden et al., 2006. “Reduction in Fine Particulate Air 

Pollution and Mortality.” American Journal of Respiratory and 

Critical Care Medicine. 173:667–672.
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economic studies used to configure the benefit and cost models. 

Gaps in the scientific literature often result in the inability 

to estimate quantitative changes in health and environmental 

effects, or to assign economic values even to those health and 

environmental outcomes that can be quantified. The uncertainties 

in the underlying scientific and economics literature (that may 

result in overestimation or underestimation of the co-benefits) 

are discussed in detail in the RIA. Despite these uncertainties, 

we believe the benefit analysis for this rule provides a 

reasonable indication of the expected health co-benefits of the 

rulemaking in future years under a set of reasonable 

assumptions.

When characterizing uncertainty in the PM-mortality 

relationship, the EPA has historically presented a sensitivity 

analysis applying alternate assumed thresholds in the PM 

concentration-response relationship. In its synthesis of the 

current state of the PM science, the EPA’s 2009 Integrated 

Science Assessment for Particulate Matter concluded that a nothreshold log-linear model most adequately portrays the PMmortality concentration-response relationship.

In the RIA accompanying this rulemaking, rather than 

segmenting out impacts predicted to be associated with levels 

above and below a “bright line” threshold, the EPA includes a 
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“lowest measured level” (LML) analysis that illustrates the 

increasing uncertainty that characterizes exposure attributed to 

levels of PM2.5 below the LML of each epidemiological study used 

to estimate PM2.5-related premature death. Figures provided in 

the RIA show the distribution of baseline exposure to PM2.5, as 

well as the lowest air quality levels measured in each of the 

epidemiology cohort studies. This information provides a context 

for considering the likely portion of PM-related mortality 

benefits occurring above or below the LML of each study; in 

general, our confidence in the size of the estimated reduction 

in PM2.5-related premature mortality diminishes as baseline 

concentrations of PM2.5 are lowered.

Based on the modeled interim baseline which is 

approximately equivalent to the final baseline (see Appendix A 

of the RIA), 11 percent and 73 percent of the estimated avoided 

mortality impacts occur at or above an annual mean PM2.5 level of 

10 μg/m3 (the LML of the Laden et al., 2006 study)or 7.5 μg/m3

(the LML of the Pope, et al., 2002 study), respectively. 

Although the LML analysis provides some insight into the level 

of uncertainty in the estimated PM mortality benefits, the EPA 

does not view the LML as a threshold and continues to quantify 

PM-related mortality impacts using a full range of modeled air 

quality concentrations. A large fraction of the PM2.5-related 
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Page 681 of 1103

benefits occur below the level of the National Ambient Air 

Quality Standard (NAAQS) for PM2.5 at 15 μg/m3, which was set in 

2006. It is important to emphasize that NAAQS are not set at a 

level of zero risk. Instead, the NAAQS reflect the level 

determined by the Administrator to be protective of public 

health within an adequate margin of safety, taking into 

consideration effects on susceptible populations. While benefits 

occurring below the standard may be less certain than those 

occurring above the standard, EPA considers them to be 

legitimate components of the total benefits estimate.

It is important to note that the monetized benefits include 

many but not all health effects associated with PM2.5 exposure. 

Benefits are shown as a range from Pope, et al. (2002), to 

Laden, et al. (2006). These studies assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because there is no clear 

scientific evidence that would support the development of 

differential effects estimates by particle type. Even though we 

assume that all fine particles have equivalent health effects, 

the benefit-per-ton estimates vary between directly-emitted 

particles (carbonaceous and crustal particles) and SO2 emissions 

that form sulfate particles, based on the location of emission 

changes and magnitude of population exposure changes.
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Regardless, however, the assumption that all fine particles are 

equally potent in causing premature mortality adds uncertainty 

to the benefits estimate.

b. Non-Climate Welfare Co-Benefits. Emission controls installed 

to comply with the requirements specified in this rule will also 

generate co-benefits by improving visibility. We anticipate that 

improvements in visibility in Class I areas as well as 

residential areas where people live, work, and recreate could be 

substantial. Because full-scale air quality modeling was not 

performed for this rule, we are unable to quantify these 

visibility co-benefits for this rule. However, the estimated 

value of visibility benefits calculated from the modeled interim 

baseline and policy scenario was $1.1 billion (in 2007$). These 

visibility benefits are not included in the total co-benefits 

estimate of the final policy scenario used as a basis for this 

final rule. The distribution of emission reductions did not 

change substantially in the visibility regions studied, 

therefore visibility benefits of the final policy scenario are 

likely to be of a similar magnitude.

Ecosystem and other welfare effects include reduced 

acidification and, in the case of NOX, eutrophication of water 

bodies; possible reduced nitrate contamination of drinking 

water; ozone vegetation damage; a reduction in the role of 
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Page 683 of 1103

sulfate in Hg methylation; and reduced acid and particulate 

deposition that causes damages to cultural monuments, as well as

soiling and other materials damage. To illustrate the important 

nature of benefit categories the EPA is currently unable to 

monetize, we discuss the potential public welfare and 

environmental impacts related to reductions in emissions 

required by this rule in the RIA, including reduced visibility 

impairment, reduced effects from acid deposition, reduced 

effects from nutrient enrichment, and reduced vegetation effects 

from ambient exposure to SO2 and NO2.

c. Climate co-benefits. This rule is expected to reduce CO2

emissions from the electricity sector. The EPA has assigned a 

dollar value to reductions in CO2 emissions using recent 

estimates of the “social cost of carbon” (SCC). The SCC is an 

estimate of the monetized damages associated with an incremental 

increase in carbon emissions in a given year or the per metric 

ton benefit estimate relating to decreases in CO2 emissions. It 

is intended to include (but is not limited to) changes in net 

agricultural productivity, human health, property damage from 

increased flood risk, and the value of ecosystem services due to 

climate change. 

The SCC estimates used in this analysis were developed 

through an interagency process that included the EPA and other 
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Page 684 of 1103

executive branch entities, and that concluded in February 2010. 

We first used these SCC estimates in the benefits analysis for 

the final joint EPA/DOT Rulemaking to establish Light-Duty 

Vehicle Greenhouse Gas Emission Standards and Corporate Average 

Fuel Economy Standards; see the rule’s preamble for discussion 

about application of the SCC (75 FR 25324; May 7, 2010). The SCC 

Technical Support Document (SCC TSD) provides a complete 

discussion of the methods used to develop these SCC estimates.378

The interagency group selected four SCC values for use in 

regulatory analyses, which we have applied in this analysis: 

$5.9, $24.3, $39, and $74.4 per metric ton of CO2 emissions in 

2016, in 2007 dollars. The first three values are based on the 

average SCC from three integrated assessment models, at discount 

rates of 5, 3, and 2.5 percent, respectively. Social cost of 

carbon values at several discount rates are included because the 

literature shows that the SCC is quite sensitive to assumptions 

about the discount rate, and because no consensus exists on the 

appropriate rate to use in an intergenerational context. The 

 

378 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 

Document: Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social 

Cost of Carbon, with participation by Council of Economic 

Advisers, Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (February 2010). 

Also available at http://epa.gov/otaq/climate/regulations.htm 
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fourth value is the 95th percentile of the SCC from all three 

values at a 3 percent discount rate. It is included to represent 

higher-than-expected impacts from temperature change further out 

in the extremes of the SCC distribution. Low probability, high 

impact events are incorporated into all of the SCC values 

through explicit consideration of their effects in two of the 

three values as well as the use of a probability density 

function for equilibrium climate sensitivity. Treating climate 

sensitivity probabilistically results in more high temperature 

outcomes, which in turn leads to higher projections of damages.

Applying the global SCC estimates using a 3 percent 

discount rate, we estimate the value of the climate related 

benefits of this rule in 2016 is $360 million (2007$), as shown 

in Table 11. See the RIA for more detail on the methodology used 

to calculate these benefits and additional estimates of climate 

benefits using different discount rates and the 95th percentile 

of the 3 percent discount rate SCC. Important limitations and 

uncertainties of the SCC approach are also described in the RIA.

TABLE 11. ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-

RELATED HEALTH BENEFITS AND CLIMATE BENEFITS IN 2016a

Effect Monetized Benefits

Monetized Health Co-Benefits

Pope, et al. (2002)

3% discount rate $36

($2.8 - $110)

7% discount rate $33

($2.5 - $100)
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Laden, et al. (2006)

3% discount rate $89

($7.7 - $260)

7% discount rate $80

($6.9 - $240)

Climate-related Co-Benefits (3% 

discount rate) $0.36

Monetized Total Co-Benefits

Pope, et al. (2002)

3% discount rate $37

($3.2 - $110)

7% discount rate $33

($2.9 - $100)

Laden, et al. (2006)

3% discount rate $90

($8.0 - $260)

7% discount rate $81

($7.3 - $240)

a Values rounded to two significant figures. Co-benefits from 

reducing exposure to ozone, other criteria pollutants, and HAP, 

as well as reducing visibility impairment and ecosystem effects 

are not included here.

Our best estimate for the monetized total health and 

climate co-benefits of this rule in 2016 at a 3 percent discount 

rate is between $37 billion and $90 billion or between $33 

billion and $81 billion (2007$) at a 7 percent discount rate.

These estimates account for the quantified health and climate 

benefits described in Table 11.

XIII. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review and 

Executive Order 13563, Improving Regulation and Regulatory 

Review

Under EO 12866 (58 FR 51735; October 4, 1993), this action 

is an “economically significant regulatory action” because it is 
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likely to have an annual effect on the economy of $100 million 

or more or adversely affect in a material way the economy, a 

sector of the economy, productivity, competition, jobs, the 

environment, public health or safety, or state, local, or tribal

governments or communities. Accordingly, the EPA submitted this 

action to the OMB for review under Executive Orders 12866 and 

13563 and any changes in response to OMB recommendations have 

been documented in the docket for this action. For more 

information on the costs and benefits for this rule, please 

refer to Table 2 of this preamble.

When estimating the human health benefits and compliance 

costs in Table 2 of this preamble, the EPA applied methods and 

assumptions consistent with the state-of-the-science for human 

health impact assessment, economics and air quality analysis. 

The EPA applied its best professional judgment in performing 

this analysis and believes that these estimates provide a 

reasonable indication of the expected benefits and costs to the 

nation of this rulemaking. The RIA available in the docket 

describes in detail the empirical basis for the EPA’s 

assumptions and characterizes the various sources of 

uncertainties affecting the estimates below. In doing what is 

laid out above in this paragraph, the EPA adheres to EO 13563, 

“Improving Regulation and Regulatory Review,” (76 FR 3821;
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January 18, 2011), which is a supplement to EO 12866.

In addition to estimating costs and benefits, EO 13563 

focuses on the importance of a “regulatory system 

[that]...promote[s] predictability and reduce[s] uncertainty”

and that “identify[ies] and use[s] the best, most innovative, 

and least burdensome tools for achieving regulatory ends.” In 

addition, EO 13563 states that “[i]n developing regulatory 

actions and identifying appropriate approaches, each agency 

shall attempt to promote such coordination, simplification, and 

harmonization. Each agency shall also seek to identify, as 

appropriate, means to achieve regulatory goals that are designed 

to promote innovation.” We recognize that the utility sector 

faces a variety of requirements, including ones under CAA 

section 110(a)(2)(D) dealing with the interstate transport of 

emissions contributing to ozone and PM air quality problems, 

with coal combustion wastes, and with the implementation of CWA 

section 316(b). In developing today’s final rule, the EPA

recognizes that it needs to approach these rulemakings in ways 

that allow the industry to make practical investment decisions 

that minimize costs in complying with all of the final rules, 

while still achieving the fundamentally important environmental 

and public health benefits that underlie the rulemakings.

A summary of the monetized costs, benefits, and net 
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benefits for the final rule at discount rates of 3 percent and 7 

percent is in Table 2 of this preamble. For more information on 

the analysis, please refer to the RIA for this rulemaking, which 

is available in the docket.

B. Paperwork Reduction Act

The information collection requirements in this rule have 

been submitted for approval to the OMB under the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. The Information Collection 

Request (ICR) document prepared by the EPA has been assigned EPA 

ICR number 2137.06. 

The information collection requirements are not enforceable 

until OMB approves them. The information requirements are based 

on notification, recordkeeping, and reporting requirements in 

the NESHAP General Provisions (40 CFR Part 63, subpart A), which 

are mandatory for all operators subject to national emission 

standards. These recordkeeping and reporting requirements are 

specifically authorized by CAA section 114 (42 U.S.C. 7414). All 

information submitted to the EPA pursuant to the recordkeeping 

and reporting requirements for which a claim of confidentiality 

is made is safeguarded according to Agency policies set forth in 

40 CFR Part 2, subpart B. This final rule requires maintenance 

inspections of the control devices but would not require any 

notifications or reports beyond those required by the General 
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Provisions. The recordkeeping requirements require only the 

specific information needed to determine compliance.

When a malfunction occurs, sources must report them 

according to the applicable reporting requirements of 40 CFR 

part 63, subpart UUUUU. An affirmative defense to civil 

penalties for exceedances of emission limits that are caused by 

malfunctions is available to a source if it can demonstrate that 

certain criteria and requirements are satisfied. The criteria 

ensure that the affirmative defense is available only where the 

event that causes an exceedance of the emission limit meets the 

narrow definition of malfunction in 40 CFR 63.2 (sudden, 

infrequent, not reasonable preventable, and not caused by poor 

maintenance and or careless operation) and where the source took 

necessary actions to minimize emissions. In addition, the source 

must meet certain notification and reporting requirements. For 

example, the source must prepare a written root cause analysis 

and submit a written report to the Administrator documenting 

that it has met the conditions and requirements for assertion of 

the affirmative defense. 

For this rule, EPA is adding affirmative defense to the 

estimate of burden in the ICR. To provide the public with an 

estimate of the relative magnitude of the burden associated with 

an assertion of the affirmative defense position adopted by a 
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source, the EPA has provided administrative adjustments to this 

ICR that shows what the notification, recordkeeping, and 

reporting requirements associated with the assertion of the 

affirmative defense might entail. The EPA’s estimate for the 

required notification, reports, and records, including the root 

cause analysis, associated with a single incident totals 

approximately totals $3,141, and is based on the time and effort 

required of a source to review relevant data, interview plant 

employees, and document the events surrounding a malfunction 

that has caused an exceedance of an emission limit. The estimate 

also includes time to produce and retain the record and reports 

for submission to EPA. The EPA provides this illustrative 

estimate of this burden, because these costs are only incurred 

if there has been a violation, and a source chooses to take 

advantage of the affirmative defense.

The EPA provides this illustrative estimate of this burden 

because these costs are only incurred if there has been a 

violation and a source chooses to take advantage of the 

affirmative defense. Given the variety of circumstances under 

which malfunctions could occur, as well as differences among 

sources' operation and maintenance practices, we cannot reliably 

predict the severity and frequency of malfunction-related excess 

emissions events for a particular source. It is important to 
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note that the EPA has no basis currently for estimating the 

number of malfunctions that would qualify for an affirmative 

defense. Current historical records would be an inappropriate 

basis, as source owners or operators previously operated their 

facilities in recognition that they were exempt from the 

requirement to comply with emissions standards during 

malfunctions. Of the number of excess emissions events reported 

by source operators, only a small number would be expected to 

result from a malfunction (based on the definition above), and 

only a subset of excess emissions caused by malfunctions would 

result in the source choosing to assert the affirmative defense. 

Thus, we believe the number of instances in which source 

operators might be expected to avail themselves of the 

affirmative defense will be extremely small. 

For this reason, we estimate no more than two such 

occurrences for all sources subject to 40 CFR Part 63, subpart 

UUUUU over the 3-year period covered by this ICR. We expect to 

gather information on such events in the future, and will revise 

this estimate as better information becomes available. 

The annual monitoring, reporting, and record-keeping burden 

for this collection (averaged over the first 3 years after the 

effective date of the standards) is estimated to be $207.6 

million. This includes 700,296 labor hours per year at a total 
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labor cost of $49.1 million per year, annualized capital costs 

of $81.9 million, and annual operating and maintenance costs of 

$76.5 million. This estimate includes initial and annual 

performance tests, semiannual excess emission reports, 

developing a monitoring plan, notifications, and recordkeeping. 

All burden estimates are in 2007 dollars and represent the most 

cost effective monitoring approach for affected facilities.

Burden is defined at 5 CFR 1320.3(b).

An Agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for our regulations are listed in 40 CFR Part 9. When 

this ICR is approved by OMB, the Agency will publish a technical 

amendment to 40 CFR Part 9 in the Federal Register to display 

the OMB control number for the approved information collection 

requirements contained in this final rule.

C. Regulatory Flexibility Act, as Amended by the Small Business 

Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 

601 et seq.

The Regulatory Flexibility Act (RFA) generally requires an 

agency to prepare a regulatory flexibility analysis of any rule 

subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the 
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agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small 

entities include small businesses, small organizations, and 

small governmental jurisdictions.

For purposes of assessing the impacts of today’s rule on 

small entities, small entity is defined as: (1) a small business 

that is an electric utility producing 4 billion kilowatt-hours 

or less as defined by NAICS codes 221122 (fossil fuel-fired 

electric utility steam generating units) and 921150 (fossil 

fuel-fired electric utility steam generating units in Indian 

country); (2) a small governmental jurisdiction that is a 

government of a city, county, town, school district or special 

district with a population of less than 50,000; and (3) a small 

organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its 

field.

Pursuant to RFA section 603, the EPA prepared an initial 

regulatory flexibility analysis (IRFA) for the proposed rule and 

convened a Small Business Advocacy Review Panel to obtain advice 

and recommendations of representatives of the regulated small 

entities. A detailed discussion of the Panel’s advice and 

recommendations is found in the Panel Report (EPA-HQ-OAR-2009-

0234-2921). A summary of the Panel’s recommendations is 
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presented at 76 FR 24975.

As required by RFA section 604, we also prepared a final 

regulatory flexibility analysis (FRFA) for the final rule. The 

FRFA addresses the issues raised by public comments on the IRFA, 

which was part of the proposal of this rule. The FRFA is 

summarized below and in the RIA.

1. Reasons Why Action Is Being Taken

In 2000, the EPA made a finding that it was appropriate and 

necessary to regulate coal- and oil-fired EGUs under CAA section 

112 and listed EGUs pursuant to CAA section 112(c). On March 29, 

2005 (70 FR 15994), the EPA published a final rule (2005 Action) 

that removed EGUs from the list of sources for which regulation 

under CAA section 112 was required. That rule was published in 

conjunction with a rule requiring reductions in emissions of Hg

from EGUs pursuant to CAA section 111, i.e., CAMR, May 18, 2005, 

70 FR 28606). The 2005 Action was vacated on February 8, 2008, 

by the U.S. Court of Appeals for the District of Columbia 

Circuit. As a result of that vacatur, CAMR was also vacated and 

EGUs remain on the list of sources that must be regulated under 

CAA section 112. This action provides the EPA’s final NESHAP and 

NSPS for EGUs.

2. Statement of Objectives and Legal Basis for Final Rules

The MATS will protect air quality and promote public health 
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by reducing emissions of HAP. In the December 2000 regulatory 

determination, the EPA made a finding that it was appropriate 

and necessary to regulate EGUs under CAA section 112. The 

February 2008 vacatur of the 2005 Action reverted the status of 

the rule to the December 2000 regulatory determination. Section 

112(n)(1)(A) of the CAA and the 2000 determination do not 

differentiate between EGUs located at major versus area sources 

of HAP. Thus, the NESHAP for EGUs will regulate units at both 

major and area sources. Major sources of HAP are those that have 

the potential to emit at least 10 tons per year (tpy) of any one 

HAP or at least 25 tpy of any combination of HAP. Area sources 

are any stationary sources of HAP that are not major sources.

3. Summary of Issues Raised during the Public Comment Process on 

the IRFA

The EPA received a number of comments related to the 

Regulatory Flexibility Act during the public comment process. A 

consolidated version of the comments received is reproduced 

below. These comments can also be found in their entirety in the 

response to comment document in the docket.

Comment: Several commenters expressed concern with the SBAR 

panel. Some believe Small Entity Representatives (SERs) were not 

provided with regulatory alternatives including descriptions of 

significant regulatory options, differing timetables, or 
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simplifications of compliance and reporting requirements, and 

subsequently were not presented with an opportunity to respond. 

One commenter believes the EPA’s formal SBAR Panel notification 

and subsequent information provided by the EPA to the Panel did 

not include information on the potential impacts of the rule as 

required by CAA section 609(b)(1). Additional commenters 

suggested that the EPA’s rulemaking schedule put pressure on the 

SBAR Panel through the abbreviated preparation for the Panel. 

Commenters also expressed concerns that the EPA did not provide 

participants more than cursory background information on which 

to base their comments. One commenter stated that the EPA did 

not provide deliberative materials, including draft proposed 

rules or discussions of regulatory alternatives, to the SBAR 

Panel members. One commenter stated the SBAR Panel Report does 

not meet the statutory obligation to recommend less burdensome 

alternatives. The commenter suggested the EPA panel members 

declined to make recommendations that went further than 

consideration or investigation of broad regulatory alternatives, 

with the exception of those recommendations in which the EPA 

rejected alternative interpretations of the CAA section 112 and 

relevant court cases. Two stated that the EPA did not respond to 

the concerns of the small business community, the SBA, or OMB, 

ignoring concerns expressed by the SER panelists. One commenter 
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believes the EPA failed to convene required meetings and 

hearings with affected parties as required by law for small 

business entities. One commenter stated that the SERs’ input is 

very important because more than 90 percent of public power 

utility systems meet the definition and qualify as small 

businesses under the SBREFA.

Response: The RFA requires that SBAR Panels collect advice and 

recommendations from SERs on the issues related to: 

- the number and description of the small entities to which the 

proposed rule will apply; 

- the projected reporting, recordkeeping and other compliance 

requirements of the proposed rule; 

- duplication, overlap or conflict between the proposed rule and 

other federal rules; and 

- alternatives to the proposed rule that accomplish the stated 

statutory objectives and minimize any significant economic 

impact on small entities.

The RFA does not require a covered agency to create or 

assemble information for SERs or for the government panel 

members. Although CAA section 609(b)(4) requires that the 

government Panel members review any material the covered agency 

has prepared in connection with the RFA, the law does not 

prescribe the materials to be reviewed. The EPA’s policy, as 
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reflected in its RFA guidance, is to provide as much information 

as possible, given time and resource constraints, to enable an 

informed Panel discussion. In this rulemaking, because of a 

court-ordered deadline, the EPA was unable to hold a pre-panel 

meeting but still provided SERs with the information available 

at the time, held a standard Panel Outreach meeting to collect 

verbal advice and recommendations from SERs, and provided the 

standard 14-day written comment period to SERs. The EPA received 

substantial input from the SERs, and the Panel report describes 

recommendations made by the Panel on measures the Administrator 

should consider that would minimize the economic impact of the 

proposed rule on small entities. The EPA complied with the RFA.

In addition, we met with representatives of small businesses, 

small rural cooperatives, and small governments a number of 

times during the regulatory development process to discuss their 

issues and concerns regarding the proposed MATS rule for EGUs.

Comment: One commenter requested that the EPA work with

utilities such that new regulations are as flexible and cost 

efficient as possible.

Response: In developing the final rule, the EPA has considered 

all information provided prior to, as well as in response to, 

the proposed rule. The EPA has endeavored to make the final 

regulations flexible and cost-efficient while adhering to the 
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requirements of the CAA. The final rule includes a number of 

flexibilities, such as those related to monitoring requirements, 

that will lower costs and simplify compliance for small 

businesses and local governments.

Comment: One commenter was concerned about the ability of small 

entities or nonprofit utilities such as those owned and/or 

operated by rural electric co-op utilities, and municipal 

utilities to comply with the proposed standards within 3 years. 

The commenter believes that the EPA disregarded the SER 

panelists who explained that under these current economic 

conditions they have constraints on their ability to raise 

capital for the construction of control projects and to acquire 

the necessary resources in order to meet a 3-year compliance 

deadline. Two commenters expressed concern that smaller 

utilities and those in rural areas will be unable to get vendors 

to respond to their requests for proposals, because they will be 

able to make more money serving larger utilities.

Response: The preamble to the proposed rule (76 FR 25054; May 3, 

2011) provides a detailed discussion of how the EPA determined 

compliance times for the proposed (and final) rule. The EPA has 

provided pursuant to CAA section 112(i)(3)(A) the maximum 3-year 

period for sources to come into compliance. Sources may also 

seek a 1-year extension of the compliance period from their 
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Title V permitting authority if the source needs that time to 

install controls. See CAA section 112(i)(3)(B). If the situation 

described by commenters (i.e., where small entities or nonprofit 

utilities constraints on ability to raise capital for 

construction of control projects and to acquire necessary 

resources) results in the source needing additional time to 

install controls, they would be in a position to request the 1-

year extension. 

Comment: Several commenters believe the EPA did not adequately 

consider the disproportionately large impact on smaller 

generating units. The commenters note the diseconomies in scale 

for pollution controls for such units. One commenter noted the 

rule will create a more serious compliance hurdle for small 

communities that depend on coal-fired generation to meet their 

base load demand. The commenter notes that by not 

subcategorizing units, the EPA is dictating a fuel switch due to 

the disproportionately high cost on small communities. The other 

commenter believes the MACT and NSPS standards are unachievable 

by going too far without really considering the impacts on small 

municipal units, as public power is critical to communities, 

jobs, economic viability and electric reliability. A generating 

and transmissions electric cooperative which qualifies as a 

small entity believes the rule will ultimately result in 
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increased electricity costs to its members and will negatively 

impact the economies of the primarily rural areas that they 

serve. Another commenter believes there is no legal or factual 

basis for creating subcategories or weaker standards for state, 

tribal, or municipal governments or small entities that are 

operating obsolete units, particularly given the current market 

situation and applicable equitable factors. The commenter 

suggests both the EPA’s and SBA’s analyses focus exclusively on 

the effects on entities causing HAP emissions and primarily on 

those operating obsolete EGUs, and fail to consider either 

impacts on downwind businesses and governments or the positive 

impacts on small entities and governments owning and operating 

competing, clean and modern EGUs.

Response: The EPA disagrees with the commenters’ belief that the 

impacts on smaller generating units were not adequately 

considered when developing the rule. The EPA determined the 

number of potentially impacted small entities and assessed the 

potential impact of the proposed action on small entities, 

including municipal units. A similar assessment was conducted in 

support of the final action. Specifically, the EPA estimated the 

incremental net annualized compliance cost, which is a function 

of the change in capital and operating costs, fuel costs, and 

change in revenue. The projected compliance cost was considered 
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relative to the projected revenue from generation. Thus, the 

EPA’s analysis accounts not only for the additional costs these 

entities face resulting from compliance, but also the impact of 

higher electricity prices. The EPA evaluated suggestions from 

SERs, including subcategorization recommendations. In the 

preamble to the proposed rule, the EPA explains that, normally, 

any basis for subcategorizing must be related to an effect on 

emissions, rather than some difference which does not affect 

emissions performance. The EPA does not see a distinction 

between emissions from smaller generating units versus larger 

units. The EPA acknowledges the comment that there is no legal 

or factual basis for creating subcategories or weaker standards 

for state, tribal, or municipal governments or small entities 

that are operating obsolete units.

Comment: One commenter notes that the EPA recognizes LEEs in the 

rule such that they should receive less onerous monitoring 

requirements; however, the EPA does not recognize that small and 

LEEs also need and merit more flexible and achievable pollution 

control requirements. The commenter notes that the capital costs 

for emissions control at small utility units is 

disproportionately high due to inefficiencies in Hg removal, 

space constraints for control technology retrofits, and the fact 

that small units have fewer rate base customers across which to 
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spread these costs. The commenter cites the Michigan Department 

of Environmental Quality report titled “Michigan’s Mercury 

Electric Utility Workgroup, Final Report on Mercury Emissions 

from Coal-Fired Power Plants,” (June 2005). The commenter notes 

that the EPA has addressed such concerns previously, citing the 

RIA for the 1997 8-hour ozone standard. The commenter also 

suggests smaller utility systems generally have less capital to 

invest in pollution control than larger, investor-owned systems, 

due to statutory inability to borrow from the private capital 

markets, statutory debt ceilings, limited bonding capacity, 

borrowing limitations related to fiscal strain posed by other, 

non-environmental factors, and other limitations.

Response: The EPA acknowledges that the rule contains reduced 

monitoring requirements for existing units that qualify as LEEs.

Although the EPA does not believe that reduced pollution control 

requirements are warranted for LEEs, including small entity 

LEEs, we believe that flexible and achievable pollution control 

requirements are promoted through alternative standards, 

alternative compliance options, and emissions averaging as a 

means of demonstrating compliance with the standards for 

existing EGUs.

Comment: One commenter believes that the EPA should develop more 

limited monitoring requirements for small EGUs. The commenter 
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notes small entities do not possess the monetary resources, 

manpower, or technical expertise needed to operate cutting-edge 

monitoring techniques such as Hg CEMS and PM CEMS. The commenter 

notes the EPA could have identified monitoring alternatives to 

the SER panel for consideration.

Response: The EPA provided monitoring alternatives to using PM 

CEMS, HCl CEMS, and Hg CEMS in its proposed standards and in 

this final rule. The continuous compliance alternatives are

available to all affected sources, including small entities. As 

alternatives to the use of PM CEMS and HCl CEMS, sources are

allowed to conduct additional performance testing. Sorbent trap 

monitoring is allowed in lieu of Hg CEMS.

Comment: Several commenters believe the EPA has not sufficiently 

complied with the requirements of the RFA or adequately 

considered the impact this rulemaking would have on small 

entities. One commenter believes the EPA has not engaged in 

meaningful outreach and consultation with small entities and 

therefore recommends that the EPA seek to revise the courtordered deadlines to which this rulemaking is subject, reconvene the SBAR panel, prepare a new initial regulatory 

flexibility analysis (IRFA), and issue it for additional public 

comment prior to final rulemaking. The commenter believes the 

IRFA does not sufficiently consider impacts on small entities as 
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identified in the SBAR Panel Report. The commenter believes it 

is not apparent that the EPA considered the recommendations of 

the Panel. The commenter believes the description of significant 

alternatives in the IRFA is almost entirely quoted from the SBAR 

Panel Report, which the commenter does not believe is an 

adequate substitute for the EPA’s own analysis of alternatives. 

The commenter also notes the EPA does not discuss the potential 

impacts of its decisions on small entities or the impacts of 

possible flexibilities. Where the EPA does consider regulatory 

alternatives in principle, the commenter believes it does not 

provide sufficient support for its decisions to understand on 

what basis the EPA rejected alternatives that may or may not 

have reduced burden on small entities while meeting the stated 

objectives of the rule. Additionally, the commenter notes that 

the EPA did not evaluate the economic or environmental impacts 

of significant alternatives to the proposed rule. One commenter 

believes that the EPA’s stated reasons for declining to specify 

or analyze an area source standard are inadequate under the RFA. 

The commenter believes the EPA must give serious consideration 

to regulatory alternatives that accomplish the stated objectives 

of the CAA while minimizing any significant economic impacts on 

small entities and that the EPA has a duty to specify and 

analyze this option or to more clearly state its policy reasons 
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for excluding serious consideration of a separate standard for 

area sources. A commenter believes the EPA did not fully 

consider the subcategorization of sources such as boilers 

designed to burn lignite coals versus other fossil fuels, 

especially in regard to non-mercury metal and acid gas 

emissions. The commenter references the SBAR Panel Report 

suggestion provided in the preamble of the proposed rule that 

the EPA consider developing an area source vs. major source 

distinction for the source category and the EPA’s response. 

Another commenter is concerned that the recommendations made by 

the SER participants were ignored and not discussed in the 

rulemaking. Specifically, the commenter notes the EPA did not 

discuss subcategorizing by age, type of plant, fuel, physical

space constraints or useful anticipated life of the plant. Nor 

did the EPA establish GACT for smaller emitters to alleviate 

regulatory costs and operational difficulties. A commenter 

believes it is likely that different numerical or work practice 

standards are appropriate for area sources of HAP.

Response: The EPA disagrees with one commenter’s assertion that 

the agency has not complied with the requirements of the RFA. 

The EPA complied with both the letter and spirit of the RFA, 

notwithstanding the constraints of the court-ordered deadline. 

For example, the EPA notified the Chief Counsel for Advocacy of 
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the SBA of its intent to convene a Panel; compiled a list of 

SERs for the Panel to consult with; and convened the Panel. The 

Panel met with SERs to collect their advice and recommendations; 

reviewed the EPA materials; and drafted a report of Panel 

findings. The EPA further disagrees with the commenter’s 

assertion that the EPA’s IRFA does not sufficiently consider 

impacts on small entities. The EPA’s IRFA, which is included in 

chapter 10 of the RIA for the proposed rule, addresses the 

statutorily required elements of an IRFA, such as the economic 

impact of the proposed rule on small entities and the Panel’s 

findings.

The EPA disagrees with the comment that recommendations 

made by the SERs were not considered or discussed in the 

proposed rulemaking such as recommendations regarding 

subcategorization and separate GACT standards for area sources. 

The preamble to the proposed standards includes a detailed 

discussion of how the EPA determined which subcategories and 

sources would be regulated (76 FR 25036-25037; May 3, 2011). In 

that discussion, the EPA explains the rationale for its proposed 

subcategories based on five unit design types. In addition, the 

EPA acknowledges the subcategorization suggestions from the SERs 

and explains its reasons for not subcategorizing on those bases. 

The preamble to the proposed standards also includes a 
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discussion of the SERs’ suggestion that area source EGUs be 

distinguished from major-source EGUs and the EPA’s reasons for 

not making that distinction (76 FR 25020-25021; May 3, 2011).

The EPA also disagrees with the suggestion that the Agency 

pursue an extension of the timeline for final rulemaking such 

that the SBAR Panel can be reconvened and a new IRFA can be 

prepared and released for public comment prior to the final 

rulemaking. The EPA entered into a Consent Decree to resolve 

litigation alleging that the EPA failed to perform a nondiscretionary duty to promulgate CAA section 112(d) standards 

for EGUs. See American Nurses Ass’n v. EPA, 08-2198 (D.D.C.). 

That Decree required the EPA to sign the final MATS rule by 

November 16, 2011, unless the agency sought to extend the 

deadline consistent with the requirements of the modification 

provision of the Consent Decree. The EPA and Plaintiffs 

stipulated to a 30-day extension consistent with the 

modification provisions of the Consent Decree and the rule must 

be signed no later than December 16, 2011. If plaintiffs in the 

American Nurses litigation objected to an additional extension 

request, which we believe would have been likely, the Agency 

would have had to file a motion with the Court seeking an 

extension of the deadline. Consistent with governing case law, 

the Agency would have been required to demonstrate in its motion 
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for extension that it was impossible to finalize the rule by the 

deadline provided in the Consent Decree. See Sierra Club v. 

Jackson, Civil Action No. 01-1537 (D.D.C.) (Opinion of the Court 

denying EPA’s motion to extend a consent decree deadline). The 

EPA negotiated a 30-day extension and was able to complete the 

rule by December 16, 2011; accordingly, the Agency had no basis 

for seeking a further extension of time.

A detailed description of the changes made to the rule 

since proposal, including those made as a result of feedback 

received during the public comment process can be found in 

sections VI (NESHAP) and X (NSPS) of this preamble. Changes 

explained in the identified sections include those related to 

applicability; subcategorization; work practices; periods of 

startup, shutdown, and malfunction; initial testing and 

compliance; continuous compliance; and notification, 

recordkeeping, and reporting.

4. Description and Estimate of the Affected Small Entities

For the purposes of assessing the impacts of MATS on small 

entities, a small entity is defined as:

(1) A small business according to the Small Business 

Administration size standards by the North American Industry 

Classification System (NAICS) category of the owning entity. The 

range of small business size standards for electric utilities is 
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4 billion kilowatt hours (kWh) of production or less;

(2) A small government jurisdiction that is a government 

of a city, county, town, district, or special district with a 

population of less than 50,000; and

(3) A small organization that is any not for profit 

enterprise that is independently owned and operated and is not 

dominant in its field.

The EPA examined the potential economic impacts to small 

entities associated with this rulemaking based on assumptions of 

how the affected entities will install control technologies in 

compliance with MATS. This analysis does not examine potential 

indirect economic impacts associated with this rule, such as 

employment effects in industries providing fuel and pollution 

control equipment, or the potential effects of electricity price 

increases on industries and households.

The EPA used Velocity Suite’s Ventyx data as a basis for 

identifying plant ownership and compiling the list of 

potentially affected small entities. The Ventyx dataset contains 

detailed ownership and corporate affiliation information. The 

analysis focused only on those EGUs affected by the rule, which 

includes units burning coal, oil, petroleum coke, or coal refuse 

as the primary fuel, and excludes any combustion turbine units 

or EGUs burning natural gas. Also, because the rule does not 
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affect combustion units with an equivalent electricity 

generating capacity up to 25 MW, small entities that do not own 

at least one combustion unit with a capacity greater than 25 MW 

were removed from the dataset. For the affected units remaining, 

boiler and generator capacity, heat input, generation, and 

emissions data were aggregated by owner and then by parent 

company. Entities with more than 4 billion kWh of annual 

electricity generation were removed from the list, as were 

municipal owned entities with a population greater than 50,000. 

For cooperatives, investor owned utilities, and subdivisions 

that generate less than 4 billion kWh of electricity annually 

but which may be part of a large entity, additional research on 

power sales, operating revenues, and other business activities 

was performed to make a final determination regarding size. 

Finally, small entities for which the IPM does not project 

generation in 2015 in the base case were omitted from the 

analysis because they are not projected to be operating and, 

thus, are not projected to face the costs of compliance with the 

rule. After omitting entities for the reasons above, the EPA 

identified a total of 82 potentially affected small entities 

that are affiliated with 102 EGUs.

5. Compliance Cost Impacts

The number of potentially affected small entities by 
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ownership type and potential impacts of MATS are presented in 

Chapter 7 of the RIA and summarized here. The EPA estimated the 

annualized net compliance cost to small entities to be 

approximately $106 million in 2015 (2007$).

The EPA assessed the economic and financial impacts of the 

final rule using the ratio of compliance costs to the value of 

revenues from electricity generation, and our results focus on 

those entities for which this measure could be greater than 1 

percent or 3 percent. Of the 82 small entities identified, The 

EPA’s analysis shows 40 entities may experience compliance costs 

greater than 1 percent of base generation revenues in 2015, and 

35 may experience compliance costs greater than 3 percent of 

base revenues. Also, all generating capacity at 3 small entities 

is projected to be uneconomic to maintain. In this analysis, the 

cost of withdrawing a unit as uneconomic is estimated as the 

base case profit that is forgone by not operating under the 

policy case. Because 35 of the 82 total units, or more than 40 

percent, are estimated to incur compliance cost greater than 3 

percent of base revenues, the EPA has concluded that it cannot 

certify that there will be no significant economic impact on a 

substantial number of small entities (SISNOSE) for this rule. 

Results for small entities discussed here do not account for the 

reality that electricity markets are regulated in parts of the 
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country. Entities operating in regulated or cost-of-service 

markets should be able to recover all of their costs of 

compliance through rate adjustments.

Note that the estimated costs for small entities are 

significantly lower than those estimated by the EPA for the MATS 

proposal (which were $379 million). This is driven by a small 

group of units (less than 6 percent) which were projected to be 

uneconomic to operate under the proposal (and hence incurred 

lost profits due to lost electricity revenues), but are now 

projected to continue their operations under MATS. In addition, 

the EPA’s modeling indicates one unit that would have operated 

at a low capacity factor under the base case would find it 

economical to increase its generation significantly under MATS 

to meet electricity demand in its region. Excluding this unit, 

the total cost impacts across all entities would be roughly $175 

million. Changes in compliance behavior for this small group of 

units, in particular the one unit which operates at a higher 

capacity factor, has a substantial impact on total costs as 

their increased generation revenues offsets a large portion of 

the compliance costs. 

The most significant components of incremental costs to 

these entities are changes in electricity revenues, followed by 

the increased capital and operating costs for retrofits. Capital 
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and operating costs increase across all ownership types, but the 

direction of changes in electricity revenues varies among 

ownership types. All ownership types, with the exception of 

private entities, experience a net gain in electricity revenues 

under the MATS, unlike projections from the EPA’s modeling 

during the proposal, where only municipals benefitted from 

higher electricity revenues. The change in electricity revenue 

takes into account both the profit lost from units that do not 

operate under the policy case and the difference in revenue for 

operating units under the policy case. According to the EPA’s 

modeling, an estimated 274 MW of capacity owned by small 

entities are considered uneconomic to operate under the policy 

case, resulting in a net loss of $13 million (in 2007$) in 

profits. On the other hand, many operating units actually 

increase their electricity revenue due to higher electricity 

prices under MATS. In addition, as mentioned above, the EPA’s 

modeling indicates one unit finds it economical to increase its 

capacity factor significantly under the policy case which 

results in significantly higher revenues offsetting the costs. 

6. Description of Steps to Minimize Impacts on Small Entities

Consistent with the requirements of the RFA and SBREFA, the 

EPA has taken steps to minimize the significant economic impact 

on small entities. Because this rule does not affect units with 
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a generating capacity of less than 25 MW, small entities that do 

not own at least one generating unit with a capacity greater 

than 25 MW are not subject to the rule. According to the EPA’s 

analysis, among the coal- and oil-fired EGUs (i.e., excluding 

combined cycle gas turbines and gas combustion turbines) about 

26 potentially small entities only own EGUs with a capacity less 

than or equal to 25 MW, and none of those entities are subject 

to the final rule based on the statutory definition of 

potentially regulated units. 

For units affected by the proposed rule, the EPA considered 

a number of comments received, both during the Small Business 

Advocacy Review (SBAR) Panel and the public comment period. 

While none of the alternatives adopted is specifically applied 

to small entities, the EPA believes these modifications will 

make compliance less onerous for all regulated units, including 

those owned by small entities.

a. Work practice standards. The EPA proposed numerical emission 

standards that would apply at all times, including 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 

startup and shutdown. The EPA is also finalizing work practice 

standards for organic HAP from all subcategories of EGUs. 
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Descriptions of the work practice requirements for startup and 

shutdown, as well as organic HAP and limited-use liquid oilfired EGUs, can be found in section VI.D-E. of the preamble.

b. Continuous compliance and notification, record-keeping, and 

reporting. The final rule greatly simplifies the continuous 

compliance requirements and provides two basic approaches for 

most situations: use of continuous monitoring and periodic 

testing. The frequency of periodic testing has been decreased 

from monthly in the proposal to quarterly in the final rule. In 

addition to simplifying compliance, the EPA believes these 

changes considerably reduce the overall burden associated with 

recordkeeping and reporting. These changes to the final rule are 

described in more detail in Section VI.G-H of this preamble.

c. Subcategorization. The Small Entity Representatives on the 

SBAR Panel were generally supportive of subcategorization and 

suggested a number of additional subcategories the EPA should 

consider when developing the final rule. Although it was not 

consistent with the statute to adopt the proposed subcategories, 

the EPA maintained the existing subcategories and split the 

“liquid oil-fired units” subcategory into three subcategories –

continental, non-continental units, and limited-use units.

d. MACT floor calculations. As recommended by the EPA SBAR Panel 

representative, the EPA established the MACT floors using all 
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the available ICR data that was received to the maximum extent 

possible consistent with the CAA requirements. The Agency 

believes this approach reasonably ensures that the emission 

limits selected as the MACT floors adequately represent the 

level of emissions actually achieved by the average of the units 

in the top 12 percent, considering operational variability of 

those units. 

e. Alternatives not adopted. The EPA did not adopt several of 

the suggestions posed either during the SBAR Panel or public 

comment period. The EPA did not propose a percent reduction 

standard as an alternative to the concentration-based MACT 

floor. The percent reduction format for Hg and other HAP

emissions would not have addressed the EPA’s consideration of

coal preparation practices that remove Hg and other HAP before 

firing. Also, to account for the coal preparation practices, 

sources would be required to track the HAP concentrations in 

coal from the mine to the stack, and not just before and after 

the control device(s), and such an approach would be difficult 

to implement and enforce. Furthermore, the EPA does not believe 

the percent reduction standard is in line with the Court’s 

interpretation of the CAA section 112 requirements. Even if we 

believed it was appropriate to establish a percent reduction 

standard, we do not have the data necessary to establish percent 
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reduction standards for HAP, as explained further in the 

response to comments document.

The EPA determined not to establish GACT standards for area 

sources for a number of reasons. The data show that similar HAP 

emissions and control technologies are found on both major and 

area sources greater than 25 MW, and some large units are 

synthetic area sources. In fact, because of the significant 

number of well-controlled EGUs of all sizes, we believe it would 

be difficult to make a distinction between MACT and GACT. 

Moreover, the EPA believes the standards for area source EGUs

should reflect MACT, rather than GACT, because there is no 

essential difference between area source and major source EGUs 

with respect to emissions of HAP. 

The EPA determined not to exercise its discretionary 

authority to establish health-based emission standards for HCl

and other HAP acid gases. Given the limitations of the currently 

available information (e.g., the HAP mix where EGUs are located, 

and the cumulative impacts of respiratory irritants from nearby 

sources), the environmental effects of HCl and the other acid 

gas HAP, and the significant co-benefits from reductions in 

criteria pollutants the EPA determined that setting a 

conventional MACT standard for HCl and the other acid gas HAP 

was the appropriate course of action.
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As required by SBREFA section 212, the EPA also is 

preparing a Small Entity Compliance Guide to help small entities 

comply with this rule. Small entities will be able to obtain a 

copy of the Small Entity Compliance guide at the following Web 

site:

http://www.epa.gov/airquality/powerplanttoxics/actions.html

D. Unfunded Mandates Reform Act of 1995

Title II of the UMRA of 1995, Public Law 104-4, establishes 

requirements for federal agencies to assess the effects of their 

regulatory actions on state, local, and tribal governments and 

the private sector. Under UMRA section 202, we generally must 

prepare a written statement, including a cost-benefit analysis, 

for proposed and final rules with “Federal mandates” that may 

result in expenditures to state, local, and tribal governments, 

in the aggregate, or to the private sector, of $100 million or 

more in any 1 year. Before promulgating a rule for which a 

written statement is needed, UMRA section 205 generally requires 

us to identify and consider a reasonable number of regulatory 

alternatives and adopt the least costly, most cost-effective or 

least burdensome alternative that achieves the objectives of the 

rule. The provisions of UMRA section 205 do not apply when they 

are inconsistent with applicable law. Moreover, UMRA section 205 

allows us to adopt an alternative other than the least costly, 
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most cost-effective or least burdensome alternative if the 

Administrator publishes with the final rule an explanation why 

that alternative was not adopted. Before we establish any 

regulatory requirements that may significantly or uniquely 

affect small governments, including tribal governments, we must 

develop a small government agency plan under UMRA section 203. 

The plan must provide for notifying potentially affected small 

governments, enabling officials of affected small governments to 

have meaningful and timely input in the development of 

regulatory proposals with significant federal intergovernmental 

mandates, and informing, educating, and advising small 

governments on compliance with the regulatory requirements.

We have determined that this rule contains a federal

mandate that may result in expenditures of $100 million or more 

for state, local, and tribal governments, in the aggregate, or 

the private sector in any 1 year. Accordingly, we have prepared 

a written statement entitled “Unfunded Mandates Reform Act 

Analysis” under UMRA section 202 that is within the RIA and 

which is summarized below.

1. Statutory Authority

As discussed elsewhere in this preamble, the statutory 

authority for this rulemaking is CAA section 112. Title III of 

the CAA Amendments was enacted to reduce nationwide air toxic 
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emissions. CAA section 112(b) lists the 188 chemicals, 

compounds, or groups of chemicals deemed by Congress to be HAP. 

These toxic air pollutants are to be regulated by NESHAP.

CAA section 112(d) directs us to develop NESHAP which 

require existing and new major sources to control emissions of 

HAP using MACT-based standards. This NESHAP applies to all coaland oil-fired EGUs.

In compliance with UMRA section 205(a), we identified and 

considered a reasonable number of regulatory alternatives. 

Additional information on the costs and environmental impacts of 

these regulatory alternatives were presented in the RIA for the 

rulemaking.

The regulatory alternative upon which this rule is based 

represents the MACT floor for all regulated pollutants for all 

but one EGU subcategory for all but one regulated pollutant for 

that subcategory. These MACT floor-based standards represent the 

least costly and least burdensome alternative. Beyond-the-floor 

emission limits for Hg are for existing coal-fired EGUs in the 

subcategory for low rank virgin coal EGUs.

2. Social Costs and Benefits

The RIA prepared for this rule including the Agency’s 

assessment of costs and benefits is in the docket.

It is estimated that HAP would be reduced by thousands of 
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tons in 2015, relative to the base case, including reductions in 

HCl, HF, metallic HAP (including Hg), and several other organic 

HAP from EGUs. Studies have determined a relationship between 

exposure to certain of these HAP and the onset of cancer; 

however, the Agency is unable to provide a monetized estimate of 

the HAP benefits at this time. In addition, significant 

reductions in PM2.5 and SO2 will occur, including approximately 53 

thousand tons of PM2.5 and over 1 million tons of SO2. These 

reductions will occur by 2016 and are expected to continue 

throughout the life of the affected sources. The major health 

effect associated with reducing PM2.5 and PM2.5 precursors (such 

as SO2) is a reduction in premature mortality. Other health 

effects associated with PM2.5 emission reductions include 

avoiding cases of chronic bronchitis, heart attacks, asthma 

attacks, and work-lost days (i.e., days when employees are 

unable to work). Although we are unable to monetize the benefits 

associated with the HAP emissions reductions other than for Hg

or all benefits associated with Hg reductions, we are able to 

monetize the benefits associated with the PM2.5 and SO2 emissions 

reductions. For SO2 and PM2.5, we estimated the benefits 

associated with health effects of PM but were unable to quantify 

all categories of benefits (particularly those associated with 

ecosystem and visibility effects). Our estimates of the 
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monetized benefits in 2016 associated with the implementation of 

the final rule range from $37 billion to $90 billion (2007

dollars) when using a 3 percent discount rate or from $33 

billion to $81 billion (2007 dollars) when using a 7 percent 

discount rate). Our estimate of costs is $9.6 billion (2007 

dollars). For more detailed information on the benefits and 

costs estimated for this rulemaking, refer to the RIA in the 

docket.

3. Future and Disproportionate Costs

The UMRA requires that we estimate, where accurate 

estimation is reasonably feasible, future compliance costs 

imposed by this rule and any disproportionate budgetary effects. 

Our estimates of the future compliance costs of this rule are 

discussed previously in this preamble.

The EPA assessed the economic and financial impacts of the 

rule on government-owned entities using the ratio of compliance 

costs to the value of revenues from electricity generation, and 

our results focus on those entities for which this measure could 

be greater than 1 percent or 3 percent of base revenues. The EPA 

projects that 42 government entities will have compliance costs 

greater than 1 percent of base generation revenue in 2016, and 

32 may experience compliance costs greater than 3 percent of 

base revenues. Overall, 6 units owned by government entities are 
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expected to retire. The most significant components of 

incremental costs to these entities are the increased capital 

and operating costs, followed by changes in electricity 

revenues. For more details on these results and the methodology 

behind their estimation, see the results included in chapter 7 

of the RIA.

4. Effects on the National Economy

The UMRA requires that we estimate the effect of this rule 

on the national economy. To the extent feasible, we must 

estimate the effect on productivity, economic growth, full 

employment, creation of productive jobs, and international 

competitiveness of the U.S. goods and services, if we determine 

that accurate estimates are reasonably feasible and that such 

effect is relevant and material.

The nationwide economic impact of this rule is presented in the 

RIA in the docket. This analysis provides estimates of the 

effect of this rule on some of the categories mentioned above. 

The results of the economic impact analysis are summarized 

previously in this preamble. The results show that, relative to 

baseline, there will be an average 3.1 percent increase in 

electricity price on average nationwide in 2016, with the range 

of increases from 1.3 percent to 6.3 percent in regions 

throughout the U.S., and a less than 1 percent increase in 
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natural gas price nationwide in 2016. The roughly 3 percent 

incremental price effect of this rule is small relative to the 

changes observed in the absolute levels of electricity prices 

over the last 50 years, which have ranged from as much as 23 

percent lower (in 1969) to as much as 23 percent higher (in 

1982) than prices observed in 2010.379 Power generation from 

coal-fired plants will fall by about 2 percent nationwide in 

2016. No region of the U.S. is expected to experience a doubledigit increase in retail electricity prices in 2015 or in any 

year later than that, according to the Agency’s analysis, as a 

result of this rule. To put the electricity price effects in 

context, the roughly 3 percent incremental increase in aggregate 

end-user electricity prices projected to occur over the next 4 

years is about the same as the 3 percent absolute average change 

in total end-user electricity prices observed on an annual 

basis.380 Furthermore, the roughly 3 percent incremental price 

effect of this rule is small relative to the changes observed in 

the absolute levels of electricity prices over the last 50 

years, which have ranged from as much as 23 percent lower (in 

1969) to as much as 23 percent higher (in 1982) than prices 

 

379 EIA Annual Energy Outlook 2010 annual total electricity 

prices from 1960 to 2010, Table 8-10.

380 EIA Annual Energy Outlook 2010 annual total electricity 

prices from 1960 to 2010, Table 8-10.
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observed in 2010.381 Even with this rule in effect, electricity 

prices are projected to be lower in 2015 and 2020 than they were 

in 2010.382

5. Consultation with Government

The UMRA requires that we describe the extent of the 

Agency’s prior consultation with affected state, local, and 

tribal officials, summarize the officials’ comments or concerns, 

and summarize our response to those comments or concerns. In 

addition, UMRA section 203 requires that we develop a plan for 

informing and advising small governments that may be 

significantly or uniquely impacted by a regulatory action. 

Consistent with the intergovernmental consultation provisions of 

UMRA section 204, the EPA initiated consultations with 

governmental entities affected by this rule. The EPA invited the 

following 10 national organizations representing state and local 

elected officials to a meeting held on October 27, 2010, in 

Washington D.C.: 1) National Governors Association; 2) National 

Conference of State Legislatures, 3) Council of State 

Governments, 4) National League of Cities, 5) U.S. Conference of 

Mayors, 6) National Association of Counties, 7) International 

City/County Management Association, 8) National Association of 

Towns and Townships, 9) County Executives of America, and 10) 

 

381 Ibid.

382 [NEED REFERENCE TO EIA AND/OR RIA PROJECTIONS OF 2015 AND 

2020 ELECTRICITY PRICES RELATIVE TO 2010]
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Environmental Council of States. These 10 organizations of 

elected state and local officials have been identified by the 

EPA as the “Big 10” organizations appropriate to contact for 

purpose of consultation with elected officials. The purposes of 

the consultation were to provide general background on the rule, 

answer questions, and solicit input from state/local 

governments. During the meeting, officials asked clarifying 

questions regarding CAA section 112 requirements and central 

decision points presented by the EPA (e.g., use of surrogate 

pollutants to address HAP, subcategorization of source category, 

assessment of emissions variability). They also expressed 

uncertainty with regard to how utility boilers owned/operated by 

state and local entities would be impacted, as well as with 

regard to the potential burden associated with implementing the 

rule on state and local entities (i.e., burden to re-permit 

affected EGUs or update existing permits). Officials requested, 

and the EPA provided, addresses associated with the 112 state 

and local governments estimated to be potentially impacted by 

the rule. The EPA has not received additional questions or 

requests from state or local officials.

Consistent with UMRA section 205, the EPA has identified 

and considered a reasonable number of regulatory alternatives. 

Because the potential existed for a significant impact for 
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substantial number of small entities, the EPA convened a SBAR 

Panel to obtain advice and recommendation of representatives of 

the small entities that potentially would be subject to the 

requirements of the rule. As part of that process, the EPA 

considered several options, which are discussed previously in 

this preamble. Those options included establishing emission 

limits, establishing work practice standards, establishing 

subcategories, and consideration of monitoring options. The 

regulatory alternative selected is a combination of the options 

considered and includes provisions regarding a number of the 

recommendations resulting from the SBAR Panel process as 

described below (see the Regulatory Flexibility Act discussion 

in this section of the preamble for more detail).

E. Executive Order 13132, Federalism

Under EO 13132, the EPA may not issue an action that has 

federalism implications, that imposes substantial direct 

compliance costs, and that is not required by statute, unless 

the federal government provides the funds necessary to pay the 

direct compliance costs incurred by state and local governments, 

or the EPA consults with state and local officials early in the 

process of developing the final action.

The EPA has concluded that this action may have federalism 

implications, because it may impose substantial direct 
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compliance costs on state or local governments, and the federal

government will not provide the funds necessary to pay those 

costs. Accordingly, the EPA provides the following federalism 

summary impact statement as required by section 6(b) of EO 

13132.

Based on estimates in the RIA, provided in the docket, the 

final rule may have federalism implications because the rule may 

impose approximately $294 million in annual direct compliance 

costs on an estimated 96 state or local governments. 

Specifically, we estimate that there are 80 municipalities, 5

states, and 11 political subdivisions (i.e., a public district 

with territorial boundaries embracing an area wider than a 

single municipality and frequently covering more than one county 

for the purpose of generating, transmitting and distributing 

electric energy) that may be directly impacted by this final 

rule. Responses to the EPA’s 2010 ICR were used to estimate the 

nationwide number of potentially impacted state or local 

governments. As previously explained, this 2010 survey was 

submitted to all coal- and oil-fired EGUs listed in the 2007 

version of DOE/EIA’s “Annual Electric Generator Report,” and 

“Power Plant Operations Report.”

The EPA consulted with state and local officials in the 

process of developing the rule to permit them to have meaningful 
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and timely input into its development. The EPA met with 10 

national organizations representing state and local elected 

officials to provide general background on the rule, answer 

questions, and solicit input. In the final rule, EPA has 

provided flexibilities that will lower compliance costs for 

these entities. The EPA also recognizes that municipalities may 

need a longer compliance timeframe because of required approval 

processes.

F. Executive Order 13175, Consultation and Coordination with 

Indian Tribal Governments

Subject to EO 13175 (65 FR 67249; November 9, 2000) the EPA

may not issue a regulation that has tribal implications, that 

imposes substantial direct compliance costs, and that is not 

required by statute, unless the federal government provides the 

funds necessary to pay the direct compliance costs incurred by 

tribal governments, or the EPA consults with tribal officials 

early in the process of developing the proposed regulation and 

develops a tribal summary impact statement. Executive Order

13175 requires the EPA to develop an accountable process to 

ensure “meaningful and timely input by Tribal officials in the 

development of regulatory policies that have Tribal

implications.”

The EPA has concluded that this action may have tribal
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implications. The EPA offered consultation with tribal officials 

early in the regulation development process to permit them an 

opportunity to have meaningful and timely input. Consultation 

letters were sent to 584 tribal leaders and provided information 

regarding the EPA’s development of this rule and offered 

consultation. At the request of the tribes, three consultation 

meetings were held: December 7, 2010, with the Upper Sioux 

Community of Minnesota; December 13, 2010, with Moapa Band of 

Paiutes, Forest County Potawatomi, Standing Rock Sioux Tribal 

Council, and Fond du Lac Band of Chippewa; January 5, 2011, with 

the Forest County Potawatomi, and a representative from the 

National Tribal Air Association (NTAA). In these meetings, the 

EPA presented the authority under the CAA used to develop these 

rules and an overview of the industry and the industrial 

processes that have the potential for regulation. Tribes 

expressed concerns about the impact of EGUs in Indian country. 

Specifically, they were concerned about potential Hg deposition 

and the impact on the water resources of the tribes, with 

particular concern about the impact on subsistence lifestyles 

for fishing communities, the cultural impact of impaired water 

quality for ceremonial purposes, and the economic impact on 

tourism. In light of these concerns, the tribes expressed 

interest in an expedited implementation of the rule. Other 
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concerns expressed by tribes related to how the Agency would 

consider variability in setting the standards, and the use of 

tribal-specific fish consumption data from the tribes in our 

assessments. They were not supportive of using work practice 

standards as part of the rule, and asked the Agency to consider 

going beyond the MACT floor to offer more protection for the 

tribal communities.

In addition to these consultations, the EPA also conducted 

outreach on this rule through presentations at the National 

Tribal Forum in Milwaukee, WI; phone calls with the NTAA; and a 

webinar for tribes on the proposed rule. The EPA specifically 

requested tribal data that could support the appropriate and 

necessary analyses and the RIA for this rule. In addition, the 

EPA held individual consultations with the Navajo Nation on 

October 12, 2011; as well as the Gila River Indian Community, 

Ak-Chin Indian Community, and the Hopi Nation on October 14, 

2011. These tribes expressed concerns about the impact of the 

rule on the Navajo Generating Station (NGS), the impact on the 

cost of the water allotted to the tribes from the Central 

Arizona Project (CAP), the impact on tribal revenues from the 

coal mining operations (i.e., assumptions about reduced mining 

if NGS were to retire one or more units), and the impacts on 
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employment of tribal members at both the NGS and the mine. More 

specific comments can be found in the docket. 

The EPA will continue to work with these and other 

potentially affected tribes as this final rule is implemented.

G. Executive Order 13045, Protection of Children from 

Environmental Health Risks and Safety Risks

This final rule is subject to EO 13045 (62 FR 19885; April 

23, 1997) because it is an economically significant regulatory 

action as defined by EO 12866, and EPA believes that the

environmental health or safety risk addressed by this action may 

have a disproportionate effect on children. Accordingly, we have 

evaluated the environmental health or safety effects of the 

standards on children.

Although this final rule is based on technology 

performance, the standards are designed to protect against 

hazards to public health with an adequate margin of safety as 

described in Section III of this preamble. The protection 

offered by this rule is particularly important for children, 

especially the developing fetus. As referenced in Chapter 4 of 

the RIA, “Mercury and Other HAP Benefits Analysis,” children are 

more vulnerable than adults to many HAP emitted by EGUs due to 

differential behavior patterns and physiology. These unique 

susceptibilities were carefully considered in a number of 
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different ways in the analyses associated with this rulemaking, 

and are summarized in the RIA. We also estimate substantial 

health improvements for children in the form of 130,000 fewer 

asthma attacks, 3,100 fewer emergency room visits due to asthma, 

6,300 fewer cases of acute bronchitis, and approximately 140,000 

fewer cases of upper and lower respiratory illness.

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

Executive Order 13211 (66 FR 28355; May 22, 2001) requires 

EPA to prepare and submit a Statement of Energy Effects to the 

Administrator of the Office of Information and Regulatory 

Affairs, OMB, for actions identified as “significant energy 

actions.” This action, which is a significant regulatory action 

under EO 12866, is likely to have a significant adverse effect 

on the supply, distribution, or use of energy. We have prepared 

a Statement of Energy Effects for this action as follows.

We estimate a 3.1 percent price increase for electricity 

nationwide in 2016 and a less than 2 percent percentage fall in 

coal-fired power production as a result of this rule. The EPA 

projects that electric power sector-delivered natural gas prices 

will increase by about 0.6 percent over the 2015 to 2030 

timeframe. For more information on the estimated energy effects, 

please refer to the economic impact analysis for this final 
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rule. The analysis is available in the RIA, which is in the 

public docket.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act (NTTAA) of 1995 (Public Law No. 104-113; 15 

U.S.C. 272 note) directs the EPA to use voluntary consensus 

standards in its regulatory activities unless to do so would be 

inconsistent with applicable law or otherwise impractical. 

Voluntary consensus standards are technical standards (e.g., 

materials specifications, test methods, sampling procedures, 

business practices) that are developed or adopted by voluntary 

consensus standards bodies. The NTTAA directs the EPA to provide 

Congress, through OMB, explanations when the Agency decides not 

to use available and applicable voluntary consensus standards.

This rulemaking involves technical standards. The EPA cites 

the following standards in the final rule: EPA Methods 1, 2, 2A, 

2C, 2F, 2G, 3A, 3B, 4, 5, 5D, 17, 19, 23, 26, 26A, 29, 30B of 40 

CFR Part 60 and Method 320 of 40 CFR Part 63. Consistent with 

the NTTAA, the EPA conducted searches to identify voluntary 

consensus standards in addition to these EPA methods. No 

applicable voluntary consensus standards were identified for EPA 

Methods 2F, 2G, 5D, and 19. The search and review results have 

been documented and are placed in the docket for the proposed 
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rule.

The three voluntary consensus standards described below 

were identified as acceptable alternatives to EPA test methods 

for the purposes of the final rule.

The voluntary consensus standard American National 

Standards Institute (ANSI)/American Society of Mechanical 

Engineers (ASME) PTC 19-10-1981, “Flue and Exhaust Gas Analyses 

[Part 10, Instruments and Apparatus]” is cited in the final rule 

for its manual method for measuring the O2, CO2, and CO content 

of exhaust gas. This part of ANSI/ASME PTC 19-10-1981 is an 

acceptable alternative to Method 3B.

The voluntary consensus standard ASTM D6348-03 (Reapproved 

2010), “Standard Test Method for Determination of Gaseous 

Compounds by Extractive Direct Interface Fourier Transform 

(FTIR) Spectroscopy” is acceptable as an alternative to Method 

320 and is cited in the final rule, but with several conditions: 

(1) The test plan preparation and implementation in the Annexes 

to ASTM D-6348-03, Sections A1 through A8 are mandatory; and (2) 

In ASTM D6348-03 Annex A5 (Analyte Spiking Technique), the 

percent (%) R must be determined for each target analyte 

(Equation A5.5). In order for the test data to be acceptable for 

a compound, %R must be 70 % ≥ R ≤ 130%. If the %R value does not 

meet this criterion for a target compound, the test data are not 
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acceptable for that compound and the test must be repeated for 

that analyte (i.e., the sampling and/or analytical procedure 

should be adjusted before a retest). The %R value for each 

compound must be reported in the test report, and all field 

measurements must be corrected with the calculated %R value for 

that compound by using the following equation: Reported Result = 

(Measured Concentration in the Stack x 100) / % R.

The voluntary consensus standard ASTM D6784-02, “Standard 

Test Method for Elemental, Oxidized, Particle-Bound and Total 

Mercury in Flue Gas Generated from Coal-Fired Stationary Sources 

(Ontario Hydro Method),” is an acceptable alternative to use of 

EPA Method 29 for Hg only or Method 30B for the purpose of 

conducting relative accuracy tests of Hg continuous monitoring 

systems under this final rule. Because of the limitations of 

this method in terms of total sampling volume, it is not 

appropriate for use in performance testing under this rule. In 

addition to the voluntary consensus standards the EPA used in 

the final rule, the search for emissions measurement procedures 

identified 16 other voluntary consensus standards. The EPA 

determined that 14 of these 16 standards identified for 

measuring emissions of the HAP or other pollutants subject to 

emission standards in the final rule were impractical 

alternatives to EPA test methods for the purposes of this final 
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rule. Therefore, the EPA does not intend to adopt these 

standards for this purpose. The reasons for this determination 

for the 14 methods are discussed below, and the remaining 2 

methods are discussed later in this section.

The voluntary consensus standard ASTM D3154-00, “Standard 

Method for Average Velocity in a Duct (Pitot Tube Method),” is 

impractical as an alternative to EPA Methods 1, 2, 3B, and 4 for 

the purposes of this rulemaking because the standard appears to 

lack in quality control and quality assurance requirements. 

Specifically, ASTM D3154-00 does not include the following: (1) 

proof that openings of standard pitot tube have not plugged 

during the test; (2) if differential pressure gauges other than 

inclined manometers (e.g., magnehelic gauges) are used, their 

calibration must be checked after each test series; and (3) the 

frequency and validity range for calibration of the temperature 

sensors.

The voluntary consensus standard ASTM D3464-96 (Reapproved 

2001), “Standard Test Method Average Velocity in a Duct Using a 

Thermal Anemometer,” is impractical as an alternative to EPA 

Method 2 for the purposes of this rule primarily because 

applicability specifications are not clearly defined, e.g., 

range of gas composition, temperature limits. Also, the lack of 

supporting quality assurance data for the calibration procedures 
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and specifications, and certain variability issues that are not 

adequately addressed by the standard limit the EPA’s ability to 

make a definitive comparison of the method in these areas.

The voluntary consensus standard ISO 10780:1994, 

“Stationary Source Emissions–Measurement of Velocity and Volume 

Flowrate of Gas Streams in Ducts,” is impractical as an 

alternative to EPA Method 2 in this rule. The standard 

recommends the use of an L-shaped pitot, which historically has 

not been recommended by the EPA. The EPA specifies the S-type 

design which has large openings that are less likely to plug up 

with dust.

The voluntary consensus standard, CAN/CSA Z223.2-M86 

(1999), “Method for the Continuous Measurement of Oxygen, Carbon 

Dioxide, Carbon Monoxide, Sulphur Dioxide, and Oxides of 

Nitrogen in Enclosed Combustion Flue Gas Streams,” is 

unacceptable as a substitute for EPA Method 3A because it does 

not include quantitative specifications for measurement system 

performance, most notably the calibration procedures and 

instrument performance characteristics. The instrument 

performance characteristics that are provided are non-mandatory 

and also do not provide the same level of quality assurance as 

the EPA methods. For example, the zero and span/calibration 

drift is only checked weekly, whereas the EPA methods require 
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drift checks after each run.

Two very similar voluntary consensus standards, ASTM D5835-

95 (Reapproved 2001), “Standard Practice for Sampling Stationary 

Source Emissions for Automated Determination of Gas 

Concentration,” and ISO 10396:1993, “Stationary Source 

Emissions: Sampling for the Automated Determination of Gas 

Concentrations,” are impractical alternatives to EPA Method 3A 

for the purposes of this final rule because they lack in detail 

and quality assurance/quality control requirements. 

Specifically, these two standards do not include the following: 

(1) sensitivity of the method; (2) acceptable levels of analyzer 

calibration error; (3) acceptable levels of sampling system 

bias; (4) zero drift and calibration drift limits, time span, 

and required testing frequency; (5) a method to test the 

interference response of the analyzer; (6) procedures to 

determine the minimum sampling time per run and minimum 

measurement time; and (7) specifications for data recorders, in 

terms of resolution (all types) and recording intervals (digital 

and analog recorders, only).

The voluntary consensus standard ISO 12039:2001, 

“Stationary Source Emissions--Determination of Carbon Monoxide, 

Carbon Dioxide, and Oxygen--Automated Methods,” is not 

acceptable as an alternative to EPA Method 3A. This ISO standard 
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is similar to EPA Method 3A, but is missing some key features. 

In terms of sampling, the hardware required by ISO 12039:2001 

does not include a 3-way calibration valve assembly or 

equivalent to block the sample gas flow while calibration gases 

are introduced. In its calibration procedures, ISO 12039:2001 

only specifies a two-point calibration while EPA Method 3A 

specifies a three-point calibration. Also, ISO 12039:2001 does 

not specify performance criteria for calibration error, 

calibration drift, or sampling system bias tests as in the EPA 

method, although checks of these quality control features are 

required by the ISO standard.

The voluntary consensus standard ASTM D6522-00, “Standard 

Test Method for the Determination of Nitrogen Oxides, Carbon 

Monoxide, and Oxygen Concentrations in Emissions from Natural 

Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers 

and Process Heaters Using Portable Analyzers” is not an 

acceptable alternative to EPA Method 3A for measuring CO and O2

concentrations for this final rule as the method is designed for 

application to sources firing natural gas.

The voluntary consensus standard ASME PTC-38-80 R85 (1985), 

“Determination of the Concentration of Particulate Matter in Gas 

Streams,” is not acceptable as an alternative for EPA Method 5 

because ASTM PTC-38-80 is not specific about equipment 
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requirements, and instead presents the options available and the 

pros and cons of each option. The key specific differences 

between ASME PTC-38-80 and the EPA methods are that the ASME 

standard: (1) allows in-stack filter placement as compared to 

the out-of-stack filter placement in EPA Methods 5 and 17; (2) 

allows many different types of nozzles, pitots, and filtering 

equipment; (3) does not specify a filter weighing protocol or a 

minimum allowable filter weight fluctuation as in the EPA 

methods; and (4) allows filter paper to be only 99 percent 

efficient, as compared to the 99.95 percent efficiency required 

by the EPA methods.

The voluntary consensus standard ASTM D3685/D3685M-98, 

“Test Methods for Sampling and Determination of Particulate 

Matter in Stack Gases,” is similar to EPA Methods 5 and 17, but 

is lacking in the following areas that are needed to produce 

quality, representative particulate data: (1) requirement that 

the filter holder temperature should be between 120oC and 134oC, 

and not just “above the acid dew-point;” (2) detailed 

specifications for measuring and monitoring the filter holder 

temperature during sampling; (3) procedures similar to EPA 

Methods 1, 2, 3, and 4, that are required by EPA Method 5; (4) 

technical guidance for performing the Method 5 sampling 

procedures, e.g., maintaining and monitoring sampling train 
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operating temperatures, specific leak check guidelines and 

procedures, and use of reagent blanks for determining and 

subtracting background contamination; and (5) detailed equipment 

and/or operational requirements, e.g., component exchange leak 

checks, use of glass cyclones for heavy particulate loading 

and/or water droplets, operating under a negative stack 

pressure, exchanging particulate loaded filters, sampling 

preparation and implementation guidance, sample recovery 

guidance, data reduction guidance, and particulate sample 

calculations input.

The voluntary consensus standard ISO 9096:1992, 

“Determination of Concentration and Mass Flow Rate of 

Particulate Matter in Gas Carrying Ducts - Manual Gravimetric 

Method,” is not acceptable as an alternative for EPA Method 5. 

Although sections of ISO 9096 incorporate EPA Methods 1, 2, and 

5 to some degree, this ISO standard is not equivalent to EPA 

Method 5 for collection of PM. The standard ISO 9096 does not 

provide applicable technical guidance for performing many of the 

integral procedures specified in Methods 1, 2, and 5. Major 

performance and operational details are lacking or nonexistent, 

and detailed quality assurance/quality control guidance for the 

sampling operations required to produce quality, representative 

particulate data (e.g., guidance for maintaining and monitoring 
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train operating temperatures, specific leak check guidelines and 

procedures, and sample preparation and recovery procedures) are 

not provided by the standard, as in EPA Method 5. Also, details 

of equipment and/or operational requirements, such as those 

specified in EPA Method 5, are not included in the ISO standard, 

e.g., stack gas moisture measurements, data reduction guidance, 

and particulate sample calculations.

The voluntary consensus standard CAN/CSA Z223.1-M1977, 

“Method for the Determination of Particulate Mass Flows in 

Enclosed Gas Streams,” is not acceptable as an alternative for 

EPA Method 5. Detailed technical procedures and quality control 

measures that are required in EPA Methods 1, 2, 3, and 4 are not 

included in CAN/CSA Z223.1. Second, CAN/CSA Z223.1 does not 

include the EPA Method 5 filter weighing requirement to repeat 

weighing every 6 hours until a constant weight is achieved. 

Third, EPA Method 5 requires the filter weight to be reported to 

the nearest 0.1 milligram (mg), while CAN/CSA Z223.1 requires 

reporting only to the nearest 0.5 mg. Also, CAN/CSA Z223.1 

allows the use of a standard pitot for velocity measurement when 

plugging of the tube opening is not expected to be a problem. 

The EPA Method 5 requires an S-shaped pitot.

The voluntary consensus standard EN 1911-1,2,3 (1998), 

“Stationary Source Emissions-Manual Method of Determination of 
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HCl-Part 1: Sampling of Gases Ratified European Text-Part 2: 

Gaseous Compounds Absorption Ratified European Text-Part 3: 

Adsorption Solutions Analysis and Calculation Ratified European 

Text,” is impractical as an alternative to EPA Methods 26 and 

26A. Part 3 of this standard cannot be considered equivalent to 

EPA Method 26 or 26A because the sample absorbing solution 

(water) would be expected to capture both HCl and chlorine gas, 

if present, without the ability to distinguish between the two. 

The EPA Methods 26 and 26A use an acidified absorbing solution 

to first separate HCl and chlorine gas so that they can be 

selectively absorbed, analyzed, and reported separately. In 

addition, in EN 1911 the absorption efficiency for chlorine gas 

would be expected to vary as the pH of the water changed during 

sampling.

The voluntary consensus standard EN 13211 (1998), is not 

acceptable as an alternative to the Hg portion of EPA Method 29 

primarily because it is not validated for use with impingers, as 

in the EPA method, although the method describes procedures for 

the use of impingers. This European standard is validated for 

the use of fritted bubblers only and requires the use of a side 

(split) stream arrangement for isokinetic sampling because of 

the low sampling rate of the bubblers (up to 3 liters per 

minute, maximum). Also, only two bubblers (or impingers) are 
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required by EN 13211, whereas EPA Method 29 require the use of 

six impingers. In addition, EN 13211 does not include many of 

the quality control procedures of EPA Method 29, especially for 

the use and calibration of temperature sensors and controllers, 

sampling train assembly and disassembly, and filter weighing.

Two of the 16 voluntary consensus standards identified in 

this search were not available at the time the review was 

conducted for the purposes of the final rule because they are 

under development by a voluntary consensus body: ASME/BSR MFC 

13M, “Flow Measurement by Velocity Traverse,” for EPA Method 2 

(and possibly 1); and ASME/BSR MFC 12M, “Flow in Closed Conduits 

Using Multiport Averaging Pitot Primary Flowmeters,” for EPA 

Method 2.

Finally, in addition to the three voluntary consensus 

standards identified as acceptable alternatives to EPA methods 

required in the final rule, the EPA is also specifying four 

voluntary consensus standards in the rule for use in sampling 

and analysis of liquid oil samples for moisture content. These 

standards are: ASTM D95-05 (Reapproved 2010), “Standard Test 

Method for Water in Petroleum Products and Bituminous Materials 

by Distillation”, ASTM D4006-11, “Standard Test Method for Water 

in Crude Oil by Distillation”, ASTM D4177-95 (Reapproved 2010), 

“Standard Practice for Automatic Sampling of Petroleum and 
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Petroleum Products,” and ASTM D4057-06 (Reapproved 2011), 

“Standard Practice for Manual Sampling of Petroleum and 

Petroleum Products.”

Table 5, section 4.1.1.5 of appendix A, and section 3.1.2 

of appendix B to subpart UUUUU, 40 CFR Part 63, list the EPA 

testing methods included in the final rule. Under section 

63.7(f) and section 63.8(f) of subpart A of the General 

Provisions, a source may apply to the EPA for permission to use 

alternative test methods or alternative monitoring requirements 

in place of any of the EPA testing methods, performance 

specifications, or procedures specified.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

Executive Order 12898 (59 FR 7629; February 16, 1994) 

establishes federal executive policy on environmental justice 

(EJ). Its main provision directs federal agencies, to the 

greatest extent practicable and permitted by law, to make EJ 

part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income populations in 

the U.S. 
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The EPA has determined that this final rule will not have 

disproportionately high and adverse human health or 

environmental effects on minority, low income, and indigenous

populations because it increases the level of environmental 

protection for all affected populations without having any 

disproportionately high and adverse human health or 

environmental effects on any population, including any minority, 

low income, and indigenous populations.

This final rule establishes national emission standards for 

new and existing EGUs that combust coal and oil. The EPA 

estimates that there are approximately 1,400 units located at 

600 facilities covered by this final rule.

This final rule will reduce emissions of all the listed HAP 

that come from EGUs. This includes metals (Hg, As, Be, Cd, Cr, 

Pb, Mn, Ni, and Se), organics (POM, acetaldehyde, acrolein, 

benzene, dioxins, ethylene dichloride, formaldehyde, and PCB), 

and acid gases (HCl and HF). At sufficient levels of exposure, 

these pollutants can cause a range of health effects including 

cancer; irritation of the lungs, skin, and mucous membranes; 

effects on the central nervous system such as memory and IQ loss 

and learning disabilities; damage to the kidneys; and other 

acute health disorders. 

The final rule will also result in substantial reductions 
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of criteria pollutants such as CO, PM, and SO2. Sulfur dioxide is 

a precursor pollutant that is often transformed into fine PM 

(PM2.5) in the atmosphere. Reducing direct emissions of PM2.5 and 

SO2 will, as a result, reduce concentrations of PM2.5 in the 

atmosphere. These reductions in PM2.5 will provide large health 

benefits, such as reducing the risk of premature mortality for 

adults, chronic and acute bronchitis, childhood asthma attacks, 

and hospitalizations for other respiratory and cardiovascular 

diseases. (For more details on the health effects of metals, 

organics, and PM2.5, please refer to the RIA contained in the 

docket for this rulemaking.) This final rule will also have a 

small effect on electricity and natural gas prices but has the 

potential to affect the cost structure of the utility industry 

and could lead to shifts in how and where electricity is

generated.

This final rule is one of a group of regulatory actions 

that the EPA has taken and will take over the next several years 

to respond to statutory and judicial mandates that will reduce 

exposure to HAP and PM2.5, as well as to other pollutants, from 

EGUs and other sources. In addition, the EPA will pursue energy 

efficiency improvements throughout the economy, along with other 

federal agencies, states and other groups. This will contribute 

to additional environmental and public health improvements while 
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lowering the costs of realizing those improvements. Together, 

these rules and actions will have substantial and long-term 

effects on both the U.S. power industry and on communities 

currently breathing dirty air. Therefore, we anticipate 

significant interest in many, if not most, of these actions from 

EJ communities, among many others.

1. Key EJ Aspects of the Rule

This is an air toxics rule; therefore, it does not permit 

emissions trading among sources. Instead, this final rule will 

place a limit on the rates of Hg and other HAP emitted from each 

affected EGU. As a result, emissions of Hg and other HAP such as 

HCl will be substantially reduced in the vast majority of 

states. In some states, however, there may be small increases in 

Hg and other HAP emissions due to shifts in electricity 

generation from EGUs with higher emission rates to EGUs with 

already low emission rates. Hydrogen chloride emissions are 

projected to increase at a small number of sources but that does 

not lead to any increased emissions at the state level. 

The primary risk analysis to support the finding that this 

final rule is both appropriate and necessary includes an 

analysis of the effects of Hg from EGUs on people who rely on 

freshwater fish they catch as a regular and frequent part of 

their diet. These groups are characterized as subsistence level 
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fishing populations or fishers. A significant portion of the 

data in this analysis came from published studies of EJ 

communities where people frequently consume locally-caught 

freshwater fish. These communities included: (1) White and black 

populations (including female and poor strata) surveyed in South 

Carolina; (2) Hispanic, Vietnamese and Laotian populations 

surveyed in California; and (3) Great Lakes tribal populations 

(Chippewa and Ojibwe) active on ceded territories around the 

Great Lakes. These data were used to help estimate risks to 

similar populations beyond the areas where the study data were

collected. For example, while the Vietnamese and Laotian survey 

data were collected in California, given the ethnic (heritage) 

nature of these high fish consumption rates, we assumed that 

they could also be associated with members of these ethnic 

groups living elsewhere in the U.S. Therefore, the high-end 

consumption rates referenced in the California study for these 

ethnic groups were used to model risk at watersheds elsewhere in 

the U.S. As a result of this approach, the specific fish 

consumption patterns of several different EJ groups are 

fundamental to the EPA’s assessment of both the underlying risks 

that make this final rule appropriate and necessary, and of the 

analysis of the benefits of reducing exposure to Hg and the 

other HAP. 
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The EPA’s full analysis of risks from consumption of Hgcontaminated fish is contained in the RIA for this rule. The 

effects of this final rule on the health risks from Hg and other 

HAP are presented in the preamble and in the RIA for this rule.

2. Potential Environmental and Public Health Impacts to 

Minority, Low Income, or Tribal Populations

The EPA has conducted several analyses that provide 

additional insight on the potential effects of this rule on EJ 

communities. These include: (1) The socio-economic distribution 

of people living close to affected EGUs who may be exposed to 

pollution from these sources; and (2) an analysis of the 

distribution of health effects expected from the reductions in 

PM2.5 that will result from implementation of this final rule 

(co-benefits).

a. Socio-Economic Distribution. As part of the analysis for this 

final rule, the EPA reviewed the aggregate demographic makeup of 

the communities near EGUs covered by this final rule. Although 

this analysis gives some indication of populations that may be 

exposed to levels of pollution that cause concern, it does not

identify the demographic characteristics of the most highly 

affected individuals or communities. Electric generating units 

usually have very tall emission stacks; this tends to disperse 

the pollutants emitted from these stacks fairly far from the 
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source. In addition, several of the pollutants emitted by these 

sources, such as a common form of Hg and SO2, are known to travel 

long distances and contribute to adverse impacts on both the 

environment and human health hundreds or even thousands of miles 

from where they were emitted (in the case of elemental Hg, 

globally).

The proximity-to-the-source review is included in the 

analysis for this final rule because some EGUs emit enough HAP

such as Ni or Cr(VI) to cause elevated lifetime cancer risks 

greater than 1 in a million in nearby communities. In addition, 

the EPA’s analysis indicates that there are localized areas with 

potential for elevated levels of Hg deposition around most U.S. 

EGUs.383

The analysis of demographic data used proximity-to-thesource as a surrogate for exposure to identify those populations 

considered to be living near affected sources, such that they 

have notable exposures to current HAP emissions from these 

sources. The demographic data for this analysis were extracted 

from the 2000 census data which were provided to the EPA by the 

U.S. Census Bureau. Distributions by race are based on 

demographic information at the census block level, and all other 

demographic groups are based on the extrapolation of census 

block group level data to the census block level. The socio-

 

383 See Excess Local Deposition TSD for more detail.
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demographic parameters used in the analysis included the 

following categories: Racial (White, African American, Native 

American, Other or Multiracial, and All Other Races); Ethnicity 

(Hispanic); and Other (Number of people below the poverty line, 

Number of people with ages between 0 and 18, Number of people 

greater than or equal to 65, Number of people with no high 

school diploma). 

In determining the aggregate demographic makeup of the 

communities near affected sources, the EPA focused on those 

census blocks within three miles of affected sources and 

determined the demographic composition (e.g., race, income, 

etc.) of these census blocks and compared them to the 

corresponding compositions nationally. The radius of 3 miles (or 

approximately 5 kilometers) is consistent with other demographic 

analyses focused on areas around potential sources. In addition, 

air quality modeling experience has shown that the area within 

three miles of an individual source of emissions can generally 

be considered the area with the highest ambient air levels of 

the primary pollutants being emitted for most sources, both in 

absolute terms and relative to the contribution of other sources 

(assuming there are other sources in the area, as is typical in 

urban areas). Although facility processes and fugitive emissions 

may have more localized impacts, the EPA acknowledges that 
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because of various stack heights there is the potential for 

dispersion beyond 3 miles. To the extent that any minority, low 

income, and indigenous subpopulation is disproportionately 

impacted by the current emissions as a result of the proximity 

of their homes to these sources, that subpopulation also stands 

to see increased environmental and health benefit from the 

emissions reductions called for by this rule. The results of the 

EPA’s demographic analysis for affected sources are shown in the 

following table:

TABLE 12. COMPARATIVE SUMMARY OF THE DEMOGRAPHICS WITHIN 5 KM (3 

MILES) OF THE AFFECTED SOURCES (POPULATION IN MILLIONS)

384

White

Africa

n 

Americ

an 

Native 

Americ

an 

Other 

and 

Multir

acial

Hispan

ic

Minori

ty385

Below 

Povert

y Line

Near

Source

Total 

(3 mi)

8.78 2.51 0.10 2.52 2.86 5.13 2.43

% of

Near

Source

Total

63% 18% 1% 18% 21% 37% 17%

National 

Total 215 35 2.49 33.3 39.1 70.8 37.1

% of 

Nation

al 

Total

75% 12% 1% 12% 14% 25% 13%

The data indicate that coal-fired EGUs are located in areas 

 

384 Racial and ethnic categories overlap and cannot be summed.

385 The “Minority” population is the overall population (in the 

first row) minus white population (in the second row).
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where the minority share of the population living within a three 

mile buffer is higher than the national average by 12 percentage 

points or 48 percent. For these same areas, the percent of the 

population below the poverty line is also higher than the 

national average by 4 percentage points or 31 percent. These 

results are presented in more detail in the “Review of Proximity 

Analysis,” February 2011, a copy of which is available in the 

docket.

b. PM2.5 (Co-Benefits) Analysis. As mentioned above, many of the 

steps EGUs will take to reduce their emissions of air toxics as 

required by this final rule will also reduce emissions of PM and 

SO2. As a result, this final rule will reduce concentrations of 

PM2.5 in the atmosphere. Exposure to PM2.5 can cause or contribute 

to adverse health effects, such as asthma and heart disease, 

that significantly affect many minority, low-income, and tribal

individuals and their communities. Fine PM (PM2.5) is 

particularly (but not exclusively) harmful to children, the 

elderly, and people with existing heart and lung diseases, 

including asthma. Exposure can cause premature death and trigger 

heart attacks, asthma attacks in children and adults with 

asthma, chronic and acute bronchitis, and emergency room visits 

and hospitalizations, as well as milder illnesses that keep 

children home from school and adults home from work. Missing 
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work due to illness or the illness of a child is a particular 

problem for people who have jobs that do not provide paid sick 

days. Low-wage employees also risk losing their jobs if they are 

absent too often, even if it is due to their own illness or the 

illness of a child or other relative. Finally, many individuals 

in these communities lack access to high quality health care to 

treat these types of illnesses. Due to all these factors, many 

minority and low-income communities are particularly susceptible 

to the health effects of PM2.5 and receive a variety of benefits 

from reducing it. 

We estimate that in 2016 the annual PM-related benefits of 

the final rule for adults include approximately 4,200 to 11,000 

fewer premature mortalities, 2,900 fewer cases of chronic 

bronchitis, 4,800 fewer non-fatal heart attacks, 2,600 fewer 

hospitalizations (for respiratory and cardiovascular disease 

combined), 3.2 million fewer days of restricted activity due to 

respiratory illness and approximately 540,000 fewer lost work 

days. As described in EO 13045, Protection of Children from 

Environmental Health Risks and Safety Risks, we also estimate 

substantial health improvements for children. 

We also examined the PM2.5 mortality risks according to 

race, income, and educational attainment. We then estimated the 

change in PM2.5 mortality risk as a result of this final rule 
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among people living in the counties with the highest (top 5 

percent) PM2.5 mortality risk in 2005. We then compared the 

change in risk among the people living in these “high-risk”

counties with people living in all other counties. 

In 2005, people living in the highest risk counties and in 

the poorest counties had a substantially higher risk of PM2.5-

related death than people living in the other 95 percent of 

counties. This was true regardless of race; the difference 

between the groups of counties for each race was large while the 

differences among races in both groups of counties was very 

small. In contrast, the analysis found that people with less 

than high school education had a significantly greater risk from 

PM2.5 mortality than people with a greater than high school 

education. This was true both for the highest-risk counties and 

for the other counties. In summary, the analysis indicates that 

in 2005, educational status, living in one of the poorest 

counties, and living in a high-risk county are associated with 

higher PM2.5 mortality risk while race is not. 

Our analysis demonstrates that this final rule will 

significantly reduce the PM2.5 mortality among all populations of 

different races living throughout the U.S. compared to both 2005 

and 2016 pre-rule (i.e., base case) levels. The analysis 

indicates that people living in counties with the highest rates 
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(top 5 percent) of PM2.5 mortality risk in 2005 receive the 

largest reduction in mortality risk after this rule takes 

effect. We also find that people living in the poorest 5 percent 

of the counties receive a larger reduction in PM2.5 mortality 

risk than all other counties. More information can be found in 

Section 7.11 of the RIA. 

The EPA estimates that the benefits of the final rule are 

distributed among races, income levels, and levels of education 

fairly evenly. However, the analysis does indicate that this 

final rule in conjunction with the implementation of existing or 

final rules (e.g., the CSAPR) will reduce the disparity in risk 

between those in the highest-risk counties and the other 95 

percent of counties for all races and educational levels. In 

addition, in many cases implementation of this final rule and 

other rules will, together, reduce risks in the highest-risk 

counties to the approximate level of risk for the rest of the 

counties as it existed before implementation of the rule. 

These results are presented in more detail in Section 7.11

of the RIA.

3. Meaningful Public Participation

The EPA defines “environmental justice” to include 

meaningful involvement of all people regardless of race, color, 

national origin, or income with respect to the development, 
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implementation, and enforcement of environmental laws, 

regulations, and policies. To promote meaningful involvement, 

the EPA publicized the rulemaking via newsletters, EJ 

listserves, and the internet, including the Office of Policy’s 

(OP) Rulemaking Gateway Web site 

(http://yosemite.epa.gov/opei/RuleGate.nsf/). During the comment 

period, the EPA discussed the proposed rule via a conference 

call with communities, conducted a community-oriented webinar on 

the proposed rule, and posted the webinar presentation on- line. 

The EPA also held three public hearings to receive additional 

input on the proposal.

There will continue to be opportunities for public notice 

and comment as the utilities move forward with implementation of 

this rule. Once the rule is finalized, affected EGUs will need 

to update their Title V operating permits to reflect their new 

emission limits, any other new applicable requirements, and the 

associated monitoring and recordkeeping from this rule. The 

Title V permitting process provides that when most permits are 

reopened (for example, to incorporate new applicable 

requirements) or renewed, there must be opportunity for public 

review and comments. In addition, after the public review 

process, the EPA has an opportunity to review the proposed 

permit and object to its issuance if it does not meet CAA 
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requirements.

4. Additional Analysis

In addition to the previously described assessment of EJ 

impacts, the EPA conducted an analysis of sub-populations with 

particularly high potential risks of Hg exposure due to high 

rates of fish consumption. These populations overlap in many 

cases with traditional EJ populations and would benefit from Hg 

reductions resulting from this rule. The EPA also conducted an 

analysis of the distribution of PM2.5-related mortality risk 

according to the race, income and education of the population 

and how MATS changes this distribution. These analyses can be 

found in Section 7.12 of the RIA.

5. Summary

This final rule strictly limits the emissions rate of Hg 

and other HAP from every affected EGU. The EPA’s analysis 

indicates substantial health benefits, including for minority, 

low income, and indigenous populations, from reductions in PM2.5.

The EPA’s analysis also indicates reductions in risks for 

individuals, including for members of minority populations, who 

eat fish frequently from U.S. lakes and rivers and who live near 

affected sources. Based on all the available information, the 

EPA has determined that this final rule will not have 

disproportionately high and adverse human health or 
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Page 763 of 1103

environmental effects on minority, low income, and indigenous

populations. The EPA is providing multiple opportunities for EJ 

communities to both learn about and comment on this rule and 

welcomes their participation as implementation of the rule 

proceeds. 

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as 

added by the Small Business Regulatory Enforcement Fairness Act 

of 1996, generally provides that before a rule may take effect, 

the agency promulgating the rule must submit a rule report, 

which includes a copy of the rule, to each House of the Congress 

and to the Comptroller General of the U.S. The EPA will submit a 

report containing this rule and other required information to 

the U.S. Senate, the U.S. House of Representatives, and the 

Comptroller General of the U.S. prior to publication of the rule 

in the Federal Register. A major rule cannot take effect until 

60 days after it is published in the Federal Register. This 

action is a “major rule” as defined by 5 U.S.C. 804(2). This 

rule will be effective [INSERT DATE 60 DAYS AFTER PUBLICATION IN 

THE FEDERAL REGISTER].
National Emission Standards for Hazardous Air Pollutants from 

Coal- and Oil-fired Electric Utility Steam Generating Units and 

Standards of Performance for Fossil-Fuel-Fired Electric Utility, 

Industrial-Commercial-Institutional, and Small IndustrialCommercial-Institutional Steam Generating Units--Page 764 of 

1103

DRAFT – DELIBERATIVE DOCUMENT – DO NOT CITE OR QUOTE

List of Subjects in 40 CFR Part 60

Environmental protection, Administrative practice and 

procedure, Air pollution control, Incorporation by reference, 

Intergovernmental relations, Reporting and recordkeeping 

requirements.

List of Subjects in 40 CFR Part 63

Environmental protection, Administrative practice and 

procedure, Air pollution control, Hazardous substances, 

Incorporation by reference, Intergovernmental relations, 

Reporting and recordkeeping requirements.

___________________

Dated: December 16, 2011.

____________________

Lisa P. Jackson,

Administrator.
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For the reasons stated in the preamble, title 40, chapter I, of 

the Code of the Federal Regulations is proposed to be amended as 

follows:

PART 60--[AMENDED]

1. The authority citation for part 60 continues to read as 

follows:

Authority: 42 U.S.C. 7401 et seq.

Subpart A-—[Amended]

2. Section 60.17 is amended:

a. By redesignating paragraphs (a)(91) and (a)(92) as paragraphs 

(a)(94) and (a)(95);

b. By redesignating paragraphs (a)(89) and (a)(90) as paragraphs 

(a)(91) and (a)(92);

c. By redesignating paragraphs (a)(54) through (a)(88) as

paragraphs (a)(55) through (a)(89);

d. By adding paragraph (a)(54);

e. By adding paragraph (a)(90); and

f. By adding paragraph (a)(93) to read as follows:

§60.17 Incorporations by reference.

* * * * *

(54) ASTM D3699-08, Standard Specification for Kerosine,

approved September 1, 2008, IBR approved for §§60.41b of subpart 

Db of this part and 60.41c of subpart Dc of this part.
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* * * * *

(90) ASTM D6751–11b, Standard Specification for Biodiesel Fuel 

Blend Stock (B100) for Middle Distillate Fuels, approved July 

15, 2011, IBR approved for §§60.41b of subpart Db of this part 

and 60.41c of subpart Dc of this part.

* * * * *

(94) ASTM D7467–10, Standard Specification for Diesel Fuel Oil, 

Biodiesel Blend (B6 to B20), approved August 1, 2010, IBR 

approved for §§60.41b of subpart Db of this part and 60.41c of 

subpart Dc of this part.

* * * * *

Subpart B-—[Amended]

3. Section 60.21 is amended as follows:

a. By revising paragraph (a).

b. By revising paragraph (f).

c. By removing paragraph (k).

Section 60.21 Definitions.

* * * * *

(a) Designated pollutant means any air pollutant, the emissions 

of which are subject to a standard of performance for new 

stationary sources, but for which air quality criteria have not 

been issued and that is not included on a list published under 

section 108(a) or section 112(b)(1)(A) of the Act.
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* * * * *

(f) Emission standard means a legally enforceable regulation 

setting forth an allowable rate of emissions into the 

atmosphere, establishing an allowance system, or prescribing 

equipment specifications for control of air pollution emissions.

* * * * *

4. Section 60.24 is amended as follows:

a. By revising paragraph (b)(1).

b. By removing paragraph (h).

Section 60.24 Emission standards and compliance schedules.

* * * * *

(b) * * *

(1) Emission standards shall either be based on an allowance 

system or prescribe allowable rates of emissions except when it 

is clearly impracticable. Such cases will be identified in the 

guideline documents issued under §60.22. Where emission 

standards prescribing equipment specifications are established, 

the plan shall, to the degree possible, set forth the emission 

reductions achievable by implementation of such specifications, 

and may permit compliance by the use of equipment determined by 

the State to be equivalent to that prescribed.

* * * * *

Subpart D-—[Amended]
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5. The subpart heading for Subpart D is revised to read as 

follows:

Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam 

Generators

6. Section 60.40 is amended by revising paragraph (e) to read as 

follows:

§60.40 Applicability and designation of affected facility.

* * * * *

(e) Any facility subject to either subpart Da or KKKK of this 

part is not subject to this subpart.

7. Section 60.41 is amended by adding the definition of “natural 

gas” to read as follows:

Section 60.41 Definitions.

* * * * *

Natural gas means a fluid mixture of hydrocarbons (e.g., 

methane, ethane, or propane), composed of at least 70 percent 

methane by volume or that has a gross calorific value between 35 

and 41 megajoules (MJ) per dry standard cubic meter (950 and 

1,100 Btu per dry standard cubic foot), that maintains a gaseous 

state under ISO conditions. In addition, natural gas contains 

20.0 grains or less of total sulfur per 100 standard cubic feet. 

Finally, natural gas does not include the following gaseous 

fuels: landfill gas, digester gas, refinery gas, sour gas, blast 
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furnace gas, coal-derived gas, producer gas, coke oven gas, or 

any gaseous fuel produced in a process which might result in 

highly variable sulfur content or heating value.

* * * * *

8. Section 60.42 is amended as follows:

a. By revising paragraph (a) introductory text.

b. By adding paragraph (d).

c. By adding (e).

Section 60.42 Standard for particulate matter (PM).

(a) Except as provided under paragraphs (b), (c), (d), and (e) 

of this section, on and after the date on which the performance 

test required to be conducted by §60.8 is completed, no owner or 

operator subject to the provisions of this subpart shall cause 

to be discharged into the atmosphere from any affected facility 

any gases that:

* * * * *

(d) An owner or operator of an affected facility that combusts 

only natural gas is exempt from the PM and opacity standards 

specified in paragraph (a) of this section.

(e) An owner or operator of an affected facility that combusts 

only gaseous or liquid fossil fuel (excluding residual oil) with 

potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less 

and that does not use post-combustion technology to reduce 
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emissions of SO2 or PM is exempt from the PM standards specified 

in paragraph (a) of this section.

9. Section 60.45 is amended as follows:

a. By revising paragraph (a).

b. By revising paragraph (b).

Section 60.45 Emissions and fuel monitoring.

(a) Each owner or operator of an affected facility subject to 

the applicable emissions standard shall install, calibrate, 

maintain, and operate continuous opacity monitoring system 

(COMS) for measuring opacity and a continuous emissions 

monitoring system (CEMS) for measuring SO2 emissions, NOX

emissions, and either oxygen (O2) or carbon dioxide (CO2) except 

as provided in paragraph (b) of this section.

(b) Certain of the CEMS and COMS requirements under paragraph 

(a) of this section do not apply to owners or operators under 

the following conditions:

(1) For a fossil-fuel-fired steam generator that combusts only 

gaseous or liquid fossil fuel (excluding residual oil) with 

potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less 

and that does not use post-combustion technology to reduce 

emissions of SO2 or PM, COMS for measuring the opacity of 

emissions and CEMS for measuring SO2 emissions are not required 

if the owner or operator monitors SO2 emissions by fuel sampling 
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and analysis or fuel receipts.

(2) For a fossil-fuel-fired steam generator that does not use a 

flue gas desulfurization device, a CEMS for measuring SO2 

emissions is not required if the owner or operator monitors SO2 

emissions by fuel sampling and analysis.

(3) Notwithstanding §60.13(b), installation of a CEMS for NOX may 

be delayed until after the initial performance tests under §60.8 

have been conducted. If the owner or operator demonstrates 

during the performance test that emissions of NOX are less than 

70 percent of the applicable standards in §60.44, a CEMS for 

measuring NOX emissions is not required. If the initial 

performance test results show that NOX emissions are greater than 

70 percent of the applicable standard, the owner or operator 

shall install a CEMS for NOX within one year after the date of 

the initial performance tests under §60.8 and comply with all 

other applicable monitoring requirements under this part.

(4) If an owner or operator is not required to and elects not to 

install any CEMS for either SO2 or NOX, a CEMS for measuring 

either O2 or CO2 is not required.

(5) For affected facilities using a PM CEMS, a bag leak 

detection system to monitor the performance of a fabric filter 

(baghouse) according to the most current requirements in section 

§60.48Da of this part, or an ESP predictive model to monitor the 
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performance of the ESP developed in accordance and operated 

according to the most current requirements in section §60.48Da 

of this part a COMS is not required.

(6) A COMS for measuring the opacity of emissions is not 

required for an affected facility that does not use postcombustion technology (except a wet scrubber) for reducing PM, 

SO2, or carbon monoxide (CO) emissions, burns only gaseous fuels 

or fuel oils that contain less than or equal to 0.30 weight 

percent sulfur, and is operated such that emissions of CO to the 

atmosphere from the affected source are maintained at levels 

less than or equal to 0.15 lb/MMBtu on a boiler operating day 

average basis. Owners and operators of affected sources electing 

to comply with this paragraph must demonstrate compliance 

according to the procedures specified in paragraphs (b)(6)(i) 

through (iv) of this section.

(i) - (iv) * * *

(7) * * *

(i) * * *

(A) If no visible emissions are observed, a subsequent Method 9 

of appendix A–4 of this part performance test must be completed 

within 12 calendar months from the date that the most recent 

performance test was conducted or within 45 days of the next day 

that fuel with an opacity standard is combusted, whichever is 
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later;

(B) If visible emissions are observed but the maximum 6-minute 

average opacity is less than or equal to 5 percent, a subsequent 

Method 9 of appendix A–4 of this part performance test must be 

completed within 6 calendar months from the date that the most 

recent performance test was conducted or within 45 days of the 

next day that fuel with an opacity standard is combusted, 

whichever is later;

(C) If the maximum 6-minute average opacity is greater than 5 

percent but less than or equal to 10 percent, a subsequent 

Method 9 of appendix A–4 of this part performance test must be 

completed within 3 calendar months from the date that the most 

recent performance test was conducted or within 45 days of the 

next day that fuel with an opacity standard is combusted, 

whichever is later; or

(D) * * *

(ii) * * *

(A) * * *

(B) If no visible emissions are observed for 10 operating days 

during which an opacity standard is applicable, observations can 

be reduced to once every 7 operating days during which an 

opacity standard is applicable. If any visible emissions are 

observed, daily observations shall be resumed.
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(iii) * * *

(8) A COMS for measuring the opacity of emissions is not 

required for an affected facility at which the owner or operator 

installs, calibrates, operates, and maintains a particulate 

matter continuous parametric monitoring system (PM CPMS) 

according to the requirements specified in subpart UUUUU of part 

63.

* * * * *

Subpart Da-—[Amended]

10. The subpart heading for Subpart Da is revised to read as 

follows:

Subpart Da—Standards of Performance for Electric Utility Steam 

Generating Units

11. Section 60.40Da is amended by revising paragraphs (b) and 

(e) to read as follows:

Section 60.40Da Applicability and designation of affected 

facility.

* * * * *

(b) * * *

(1) The IGCC electric utility steam generating unit is capable 

of combusting more than 73 MW (250 MMBtu/h) heat input of fossil 

fuel (either alone or in combination with any other fuel) in the 

combustion turbine engine and associated heat recovery steam 
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generator; and

(2) * * *

* * * * *

(e) Applicability of this subpart to an electric utility 

combined cycle gas turbine other than an IGCC electric utility 

steam generating unit is as specified in paragraphs (e)(1) 

through (3) of this section.

(1) Affected facilities (i.e. heat recovery steam generators 

used with duct burners) associated with a stationary combustion 

turbine that are capable of combusting more than MW heat input 

of fossil fuel are subject to this subpart except in cases when 

the affected facility (i.e. heat recovery steam generator) meets 

the applicability requirements of and is subject to subpart KKKK 

of this part.

(2) For heat recovery steam generators use with duct burners 

subject to this subpart, only emissions resulting from the 

combustion of fuels in the steam generating unit (i.e. duct 

burners) are subject to the standards under this subpart. (The 

emissions resulting from the combustion of fuels in the 

stationary combustion turbine engine are subject to subpart GG 

or KKKK, as applicable, of this part).

(3) Any affected facility that meets the applicability 

requirements and is subject to subpart Eb or subpart CCCC of 
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this part is not subject to the emission standards under subpart 

Da.

12. Section 60.41Da is amended as follows:

a. By revising the definitions of “boiler operating day”, 

“gaseous fuel, “integrated gasification combined cycle electric 

utility steam generating unit”, “natural gas”, “petroleum”, 

“petroleum coke”, “potential combustion concentration”, and 

“steam generating unit.”

b. By adding the definitions of “affirmative defense”, “combined 

heat and power”, “gross energy output”, “net energy output”, 

“out-of-control period”, and “petroleum coke.”

c. By deleting the definitions of “available purchase power”, 

“cogeneration”, “dry flue gas desulfurization technology “, 

“electric utility company”, “emergency condition”, “emission 

rate period”, “gross output”, “interconnected”, “net system 

capacity”, “principal company”, “responsible official”, “spare 

flue gas desulfurization system module”, “spinning reserve”, 

“system emergency reserves”, and “system load”.

Section 60.41Da Definitions.

* * * * *

Affirmative defense means, in the context of an enforcement 

proceeding, a response or defense put forward by a defendant, 

regarding which the defendant has the burden of proof, and the 
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merits of which are independently and objectively evaluated in a 

judicial or administrative proceeding.

* * * * *

Boiler operating day for units constructed, reconstructed, or 

modified before February 29, 2005, means a 24-hour period during 

which fossil fuel is combusted in a steam-generating unit for 

the entire 24 hours. For units constructed, reconstructed, or 

modified after February 28, 2005, boiler operating day means a 

24-hour period between 12 midnight and the following midnight 

during which any fuel is combusted at any time in the steamgenerating unit. It is not necessary for fuel to be combusted 

the entire 24-hour period.

* * * * *

Combined heat and power, also known as “cogeneration,” means a 

steam-generating unit that simultaneously produces both electric 

(and mechanical) and useful thermal energy from the same primary 

energy source.

* * * * *

Gaseous fuel means any fuel that is present as a gas at standard 

conditions and includes, but is not limited to, natural gas, 

refinery fuel gas, process gas, coke-oven gas, synthetic gas, 

and gasified coal.

* * * * *
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Gross energy output means:

(1) For facilities constructed, reconstructed, or modified 

before May 4, 2011, the gross electrical or mechanical output 

from the affected facility plus 75 percent of the useful thermal 

output measured relative to ISO conditions that is not used to 

generate additional electrical or mechanical output or to 

enhance the performance of the unit (i.e., steam delivered to an 

industrial process);

(2) For facilities constructed, reconstructed, or modified after 

May 3, 2011, the gross electrical or mechanical output from the 

affected facility minus any electricity used to power the 

feedwater pumps and any associated gas compressors (air 

separation unit main compressor, oxygen compressor, and nitrogen 

compressor) plus 75 percent of the useful thermal output 

measured relative to ISO conditions that is not used to generate 

additional electrical or mechanical output or to enhance the 

performance of the unit (i.e., steam delivered to an industrial 

process);

(3) For combined heat and power facilities constructed, 

reconstructed, or modified after May 3, 2011, the gross 

electrical or mechanical output from the affected facility 

divided by 0.95 minus any electricity used to power the 

feedwater pumps and any associated gas compressors (air 
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separation unit main compressor, oxygen compressor, and nitrogen

compressor) plus 75 percent of the useful thermal output 

measured relative to ISO conditions that is not used to generate 

additional electrical or mechanical output or to enhance the 

performance of the unit (i.e., steam delivered to an industrial 

process);

(4) For a IGCC electric utility generating unit that coproduces 

chemicals constructed, reconstructed, or modified after May 3, 

2011, the gross useful work performed is the gross electrical or 

mechanical output from the unit minus electricity used to power 

the feedwater pumps and any associated gas compressors (air 

separation unit main compressor, oxygen compressor, and nitrogen 

compressor) that are associated with power production plus 75 

percent of the useful thermal output measured relative to ISO 

conditions that is not used to generate additional electrical or 

mechanical output or to enhance the performance of the unit 

(i.e., steam delivered to an industrial process). Auxiliary 

loads that are associated with power production are determined 

based on the energy in the coproduced chemicals compared to the 

energy of the syngas combusted in combustion turbine engine and 

associated duct burners.

* * * * *

Integrated gasification combined cycle electric utility steam 
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generating unit or IGCC electric utility steam generating unit

means an electric utility combined cycle gas turbine that is 

designed to burn fuels containing 50 percent (by heat input) or 

more solid-derived fuel not meeting the definition of natural 

gas. The Administrator may waive the 50 percent solid-derived 

fuel requirement during periods of the gasification system 

construction or repair. No solid fuel is directly burned in the 

unit during operation.

* * * * *

Natural gas means a fluid mixture of hydrocarbons (e.g., 

methane, ethane, or propane), composed of at least 70 percent 

methane by volume or that has a gross calorific value between 35 

and 41 megajoules (MJ) per dry standard cubic meter (950 and 

1,100 Btu per dry standard cubic foot), that maintains a gaseous 

state under ISO conditions. In addition, natural gas contains 

20.0 grains or less of total sulfur per 100 standard cubic feet. 

Finally, natural gas does not include the following gaseous 

fuels: landfill gas, digester gas, refinery gas, sour gas, blast 

furnace gas, coal-derived gas, producer gas, coke oven gas, or 

any gaseous fuel produced in a process which might result in 

highly variable sulfur content or heating value.

Net energy output means the gross energy output minus the 

parasitic load associated with power production. Parasitic load 
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includes, but is not limited to, the power required to operate 

the equipment used for fuel delivery systems, air pollution 

control systems, wastewater treatment systems, ash handling and 

disposal systems, and other controls (i.e., pumps, fans, 

compressors, motors, instrumentation, and other ancillary 

equipment required to operate the affected facility).

* * * * *

Out-of-control period means any period beginning with the 

quadrant corresponding to the completion of a daily calibration 

error, linearity check, or quality assurance audit that 

indicates that the instrument is not measuring and recording 

within the applicable performance specifications and ending with 

the quadrant corresponding to the completion of an additional 

calibration error, linearity check, or quality assurance audit 

following corrective action that demonstrates that the 

instrument is measuring and recording within the applicable 

performance specifications.

Petroleum for facilities constructed, reconstructed, or modified 

before May 4, 2011, means crude oil or a fuel derived from crude 

oil, including, but not limited to, distillate oil, and residual 

oil. For units constructed, reconstructed, or modified after May 

3, 2011, petroleum means crude oil or a fuel derived from crude 

oil, including, but not limited to, distillate oil, residual 
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oil, and petroleum coke. 

Petroleum coke, also known as “petcoke,” means a carbonization 

product of high-boiling hydrocarbon fractions obtained in 

petroleum processing (heavy residues). Petroleum coke is 

typically derived from oil refinery coker units or other 

cracking processes.

Potential combustion concentration means the theoretical 

emissions (nanograms per joule (ng/J), lb/MMBtu heat input) that 

would result from combustion of a fuel in an uncleaned state 

without emission control systems. For sulfur dioxide (SO2) the 

potential combustion concentration is determined under 

§60.50Da(c).

* * * * *

Steam generating unit for facilities constructed, reconstructed, 

or modified before May 4, 2011, means any furnace, boiler, or 

other device used for combusting fuel for the purpose of 

producing steam (including fossil-fuel-fired steam generators 

associated with combined cycle gas turbines; nuclear steam 

generators are not included). For units constructed, 

reconstructed, or modified after May 3, 2011, steam generating 

unit means any furnace, boiler, or other device used for 

combusting fuel for the purpose of producing steam (including 

fossil-fuel-fired steam generators associated with combined 
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Page 783 of 1103

cycle gas turbines; nuclear steam generators are not included) 

plus any integrated combustion turbines and fuel cells.

* * * * *

13. Section 60.42Da is amended to read as follows:

Section 60.42Da Standards for particulate matter (PM).

(a) Except as provided in paragraph (f) of this section, on and 

after the date on which the initial performance test is 

completed or required to be completed under §60.8, whichever 

date comes first, an owner or operator of an affected facility 

shall not cause to be discharged into the atmosphere from any 

affected facility for which construction, reconstruction, or 

modification commenced before March 1, 2005, any gases that 

contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input.

(b) Except as provided in paragraphs (b)(1) and (b)(2) of this 

section, on and after the date the initial PM performance test 

is completed or required to be completed under §60.8, whichever 

date comes first, an owner or operator of an affected facility 

shall not cause to be discharged into the atmosphere any gases 

which exhibit greater than 20 percent opacity (6-minute 

average), except for one 6-minute period per hour of not more 

than 27 percent opacity. 

(1) An owners or operator of an affected facility that elects to 

install, calibrate, maintain, and operate a continuous emissions 
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Page 784 of 1103

monitoring system (CEMS) for measuring PM emissions according to 

the requirements of this subpart is exempt from the opacity 

standard specified in this paragraph (b) of this section.

(2) An owner or operator of an affected facility that combusts 

only natural gas is exempt from the opacity standard specified 

in paragraph (b) of this section.

(c) Except as provided in paragraphs (d) and (f) of this 

section, on and after the date on which the initial performance 

test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected 

facility that commenced construction, reconstruction, or 

modification after February 28, 2005, but before May 4, 2011, 

shall cause to be discharged into the atmosphere from that 

affected facility any gases that contain PM in excess of either:

(1) 18 ng/J (0.14 lb/MWh) gross energy output; or

(2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the 

combustion of solid, liquid, or gaseous fuel.

(d) As an alternative to meeting the requirements of paragraph 

(c) of this section, the owner or operator of an affected 

facility for which construction, reconstruction, or modification 

commenced after February 28, 2005, but before May 4, 2011, may 

elect to meet the requirements of this paragraph. On and after 

the date on which the initial performance test is completed or 
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Page 785 of 1103

required to be completed under §60.8, whichever date comes 

first, no owner or operator of an affected facility shall cause 

to be discharged into the atmosphere from that affected facility 

any gases that contain PM in excess of:

(1) 13 ng/J (0.030 lb/MMBtu) heat input derived from the 

combustion of solid, liquid, or gaseous fuel, and

(2) For an affected facility that commenced construction or 

reconstruction, 0.1 percent of the combustion concentration 

determined according to the procedure in §60.48Da(o)(5) (99.9 

percent reduction) when combusting solid, liquid, or gaseous 

fuel, or

(3) For an affected facility that commenced modification, 0.2 

percent of the combustion concentration determined according to 

the procedure in §60.48Da(o)(5) (99.8 percent reduction) when 

combusting solid, liquid, or gaseous fuel.

(e) Except as provided in paragraph (f) of this section, the 

owner or operator of an affected facility that commenced 

construction, reconstruction, or modification commenced after 

May 3, 2011, shall meet the requirements specified in paragraphs 

(e)(1) and (2) of this section.

(1) On and after the date on which the initial performance test 

is completed or required to be completed under §60.8, whichever 

date comes first, no owner or operator shall cause to be 
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Page 786 of 1103

discharged into the atmosphere from that affected facility at all 

times except during periods of startup and shutdown, any gases 

that contain PM in excess of the applicable emissions limit 

specified in paragraphs (e)(1)(i) or (ii) of this section.

(i) For an affected facility which commenced construction or 

reconstruction, any gases that contain PM in excess of either:

(A) 11 ng/J (0.090 lb/MWh) gross energy output; or

(B) 12 ng/J (0.097 lb/MWh) net energy output.

(i) For an affected facility which commenced modification, any 

gases that contain PM in excess of 13 ng/J (0.015 lb/MMBtu) heat 

input.

(2) During periods of startup and shutdown, the owner or 

operator shall meet the work practice standards specified in 

Table 3 to subpart UUUUU of Part 63.

(f) An owner or operator of an affected facility that meets the 

conditions in either paragraphs (f)(1) or (2) of this section is 

exempt from the PM emissions limits in this section.

(1) The affected facility combusts only gaseous or liquid fuels 

(excluding residual oil) with potential SO2 emissions rates of 26 

ng/J (0.060 lb/MMBtu) or less, and that does not use a postcombustion technology to reduce emissions of SO2 or PM.

(2) The affected facility is operated under a PM commercial 

demonstration permit issued by the Administrator according to 
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Page 787 of 1103

the provisions of §60.47Da.

14. Section 60.43Da is amended as follows:

a. The section heading for section 60.43Da is revised.

b. By revising paragraph (a).

c. By deleting and reserving paragraph (c).

d. By revising paragraph (f).

e. By revising paragraph(i).

f. By revising paragraph (k).

g. By adding paragraph (l).

h. By adding paragraph (m).

Section 60.43Da Standards for sulfur dioxide (SO2).

(a) * * *

(1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the 

potential combustion concentration (90 percent reduction);

(2) 30 percent of the potential combustion concentration (70 

percent reduction), when emissions are less than 260 ng/J (0.60 

lb/MMBtu) heat input;

(3) 180 ng/J (1.4 lb/MWh) gross energy output; or

(4) 65 ng/J (0.15 lb/MMBtu) heat input.

* * * * *

(f) The SO2 standards under this section do not apply to an owner 

or operator of an affected facility that is operated under an SO2

commercial demonstration permit issued by the Administrator in 
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Page 788 of 1103

accordance with the provisions of §60.47Da.

* * * * *

(i) Except as provided in paragraphs (j) and (k) of this 

section, on and after the date on which the initial performance 

test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected 

facility for which construction, reconstruction, or modification 

commenced after February 28, 2005, but before May 4, 2011, shall 

cause to be discharged into the atmosphere from that affected 

facility, any gases that contain SO2 in excess of the applicable 

emissions limit specified in paragraphs (i)(1) through (3) of 

this section.

(1) For an affected facility which commenced construction, any 

gases that contain SO2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output; or

(ii) 5 percent of the potential combustion concentration (95 

percent reduction).

(2) For an affected facility which commenced reconstruction, any 

gases that contain SO2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output;

(ii) 65 ng/J (0.15 lb/MMBtu) heat input; or

(iii) 5 percent of the potential combustion concentration (95 

percent reduction).
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(3) For an affected facility which commenced modification, any 

gases that contain SO2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output;

(ii) 65 ng/J (0.15 lb/MMBtu) heat input; or

(iii) 10 percent of the potential combustion concentration (90 

percent reduction).

* * * * *

(k) On and after the date on which the initial performance test 

is completed or required to be completed under §60.8, whichever 

date comes first, no owner or operator of an affected facility 

located in a noncontinental area for which construction, 

reconstruction, or modification commenced after February 28, 

2005, but before May 4, 2011, shall cause to be discharged into 

the atmosphere from that affected facility any gases that 

contain SO2 in excess of the applicable emissions limit specified 

in paragraphs (k)(1) and (2) of this section.

(1) For an affected facility that burns solid or solid-derived 

fuel, the owner or operator shall not cause to be discharged 

into the atmosphere any gases that contain SO2 in excess of 520 

ng/J (1.2 lb/MMBtu) heat input.

(2) For an affected facility that burns other than solid or 

solid-derived fuel, the owner or operator shall not cause to be 

discharged into the atmosphere any gases that contain SO2 in 
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Page 790 of 1103

excess of 230 ng/J (0.54 lb/MMBtu) heat input.

(l) Except as provided in paragraphs (j) and (m) of this 

section, on and after the date on which the initial performance 

test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected 

facility for which construction, reconstruction, or modification 

commenced after May 3, 2011, shall cause to be discharged into 

the atmosphere from that affected facility, any gases that 

contain SO2 in excess of the applicable emissions limit specified 

in paragraphs (l)(1) and (2) of this section.

(1) For an affected facility which commenced construction or 

reconstruction, any gases that contain SO2 in excess of either:

(i) 130 ng/J (1.0 lb/MWh) gross energy output; or

(ii) 140 ng/J (1.2 lb/MWh) net energy output; or

(iii) 3 percent of the potential combustion concentration (97 

percent reduction).

(2) For an affected facility which commenced modification, any 

gases that contain SO2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output; or

(ii) 10 percent of the potential combustion concentration (90 

percent reduction).

(m) On and after the date on which the initial performance test 

is completed or required to be completed under §60.8, whichever 
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Page 791 of 1103

date comes first, no owner or operator of an affected facility 

located in a noncontinental area for which construction, 

reconstruction, or modification commenced after May 3, 2011, 

shall cause to be discharged into the atmosphere from that 

affected facility any gases that contain SO2 in excess of the 

applicable emissions limit specified in paragraphs (n)(1) and 

(2) of this section.

(1) For an affected facility that burns solid or solid-derived 

fuel, the owner or operator shall not cause to be discharged 

into the atmosphere any gases that contain SO2 in excess of 520 

ng/J (1.2 lb/MMBtu) heat input.

(2) For an affected facility that burns other than solid or 

solid-derived fuel, the owner or operator shall not cause to be 

discharged into the atmosphere any gases that contain SO2 in 

excess of 230 ng/J (0.54 lb/MMBtu) heat input.

15. Section 60.44Da is amended to read as follows:

Section 60.44Da Standards for nitrogen oxides (NOX).

(a)Except as provided in paragraph (h) of this section, on and 

after the date on which the initial performance test is 

completed or required to be completed under §60.8, whichever 

date comes first, no owner or operator subject to the provisions 

of this subpart shall cause to be discharged into the atmosphere 

from any affected facility for which construction, 
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Page 792 of 1103

reconstruction, or modification commenced before July 10, 1997 

any gases that contain NOX (expressed as NO2) in excess of the 

applicable emissions limit in paragraphs (a)(1) and (2) of this 

section. 

(1) The owner or operator shall not cause to be discharged into 

the atmosphere any gases that contain NOX in excess of the 

emissions limit listed in the following table as applicable to 

the fuel type combusted and as determined on a 30-boiler 

operating day rolling average basis. 

Fuel type

Emission limit 

for heat input

ng/J lb/MMBtu

Gaseous fuels:

Coal-derived fuels 210 0.50

All other fuels 86 0.20

Liquid fuels:

Coal-derived fuels 210 0.50

Shale oil 210 0.50

All other fuels 130 0.30

Solid fuels:

Coal-derived fuels 210 0.50

Any fuel containing more than 25%, by weight, 

coal refuse

(1) (1)

Any fuel containing more than 25%, by weight, 

lignite if the lignite is mined in North 

Dakota, South Dakota, or Montana, and is 

combusted in a slag tap furnace2

340 0.80

Any fuel containing more than 25%, by weight, 

lignite not subject to the 340 ng/J heat input 

emission limit2

260 0.60

Subbituminous coal 210 0.50

Bituminous coal 260 0.60

Anthracite coal 260 0.60

All other fuels 260 0.60

1Exempt from NOX standards and NOX monitoring requirements.

2Any fuel containing less than 25%, by weight, lignite is not 

prorated but its percentage is added to the percentage of the 
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Page 793 of 1103

predominant fuel.

(2) When two or more fuels are combusted simultaneously in an 

affected facility, the applicable emissions limit (E) is 

determined by proration using the following formula:

Where:

En = Applicable NOX emissions limit when multiple fuels are 

combusted simultaneously (ng/J heat input);

w = Percentage of total heat input derived from the combustion 

of fuels subject to the 86 ng/J heat input standard;

x = Percentage of total heat input derived from the combustion 

of fuels subject to the 130 ng/J heat input standard;

y = Percentage of total heat input derived from the combustion 

of fuels subject to the 210 ng/J heat input standard;

z = Percentage of total heat input derived from the combustion 

of fuels subject to the 260 ng/J heat input standard; and

v = Percentage of total heat input delivered from the combustion 

of fuels subject to the 340 ng/J heat input standard.

(b) [Reserved]

(c) [Reserved]

(d) Except as provided in paragraph (h) of this section, on and 

after the date on which the initial performance test is 

completed or required to be completed under §60.8, whichever 

date comes first, no owner or operator of an affected facility 

that commenced construction, reconstruction, or modification 

after July 9, 1997, but before March 1, 2005, shall cause to be 

discharged into the atmosphere from that affected facility any 

gases that contain NOX (expressed as NO2) in excess of the 

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Page 794 of 1103

applicable emissions limit specified in paragraphs (d)(1) and 

(2) of this section as determined on a 30-boiler operating day 

rolling average basis.

(1) For an affected facility which commenced construction, any 

gases that contain NOX in excess of 200 ng/J (1.6 lb/MWh) gross 

energy output.

(2) For an affected facility which commenced reconstruction, any 

gases that contain NOX in excess of 65 ng/J (0.15 lb/MMBtu) heat 

input.

(e) Except as provided in paragraphs (f) and (h) of this 

section, on and after the date on which the initial performance 

test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected 

facility that commenced construction, reconstruction, or 

modification after February 28, 2005 but before May 4, 2011, 

shall cause to be discharged into the atmosphere from that 

affected facility any gases that contain NOX (expressed as NO2) 

in excess of the applicable emissions limit specified in 

paragraphs (e)(1) through (3) of this section as determined on a 

30-boiler operating day rolling average basis.

(1) For an affected facility which commenced construction, any 

gases that contain NOX in excess of 130 ng/J (1.0 lb/MWh) gross 

energy output.
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Page 795 of 1103

(2) For an affected facility which commenced reconstruction, any 

gases that contain NOX in excess of either:

(i) 130 ng/J (1.0 lb/MWh) gross energy output; or

(ii) 47 ng/J (0.11 lb/MMBtu) heat input.

(3) For an affected facility which commenced modification, any 

gases that contain NOX in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output; or

(ii) 65 ng/J (0.15 lb/MMBtu) heat input.

(e) On and after the date on which the initial performance test 

is completed or required to be completed under §60.8, whichever 

date comes first, the owner or operator of an IGCC electric 

utility steam generating unit subject to the provisions of this 

subpart and for which construction, reconstruction, or 

modification commenced after February 28, 2005 but before May 4, 

2011, shall meet the requirements specified in paragraphs (e)(1) 

through (3) of this section.

(1) Except as provided for in paragraphs (e)(2) and (3) of this 

section, the owner or operator shall not cause to be discharged 

into the atmosphere any gases that contain NOX (expressed as NO2) 

in excess of 130 ng/J (1.0 lb/MWh) gross energy output.

(2) When burning liquid fuel exclusively or in combination with 

solid-derived fuel such that the liquid fuel contributes 50 

percent or more of the total heat input to the combined cycle 
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Page 796 of 1103

combustion turbine, the owner or operator shall not cause to be 

discharged into the atmosphere any gases that contain NOX

(expressed as NO2) in excess of 190 ng/J (1.5 lb/MWh) gross 

energy output.

(3) In cases when during a 30-boiler operating day rolling 

average compliance period liquid fuel is burned in such a manner 

to meet the conditions in paragraph (e)(2) of this section for 

only a portion of the clock hours in the 30-day compliance 

period, the owner or operator shall not cause to be discharged 

into the atmosphere any gases that contain NOX (expressed as NO2) 

in excess of the computed weighted-average emissions limit based 

on the proportion of gross energy output (in MWh) generated 

during the compliance period for each of emissions limits in 

paragraphs (e)(1) and (2) of this section.

(f) Except as provided in paragraphs (g) of this section and 

§60.45Da, on and after the date on which the initial performance 

test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected 

facility that commenced construction, reconstruction, or 

modification after May 3, 2011, shall cause to be discharged 

into the atmosphere from that affected facility any gases that 

contain NOX (expressed as NO2) in excess of the applicable 

emissions limit specified in paragraphs (f)(1) through (3) of 
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this section.

(1) For an affected facility which commenced construction or 

reconstruction, any gases that contain NOX in excess of either:

(i) 88 ng/J (0.70 lb/MWh) gross energy output; or

(ii) 95 ng/J (0.76 lb/MWh) net energy output.

(2) For an affected facility which commenced construction or 

reconstruction and that burns 75 percent or more coal refuse (by 

heat input) on a 12-month rolling average basis, any gases that 

contain NOX in excess of either:

(i) 110 ng/J (0.85 lb/MWh) gross energy output; or

(ii) 120 ng/J (0.92 lb/MWh) net energy output.

(3) For an affected facility which commenced modification, any 

gases that contain NOX in excess of 140 ng/J (1.1 lb/MWh) gross 

energy output.

(h) The NOX emissions limits under this section do not apply to 

an owner or operator of an affected facility which is operating 

under a commercial demonstration permit issued by the 

Administrator in accordance with the provisions of §60.47Da.

16. Section 60.45Da is amended to read as follows:

a. The section heading for section 60.45Da is revised.

b. By revising paragraphs (a) and (b).

§60.45Da Alternative standards for combined nitrogen oxides (NOX) 

and carbon monoxide (CO).
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Page 798 of 1103

(a) The owner or operator of an affected facility that commenced 

construction, reconstruction, or modification after May 3, 2011 

as alternate to meeting the applicable NOX emissions limits 

specified in §60.44Da may elect to meet the applicable standards 

for combined NOX and CO specified in paragraph (b) of this 

section. 

(b) On and after the date on which the initial performance test 

is completed or required to be completed under §60.8 no owner or 

operator of an affected facility that commenced construction, 

reconstruction, or modification after May 3, 2011, shall cause 

to be discharged into the atmosphere from that affected facility 

any gases that contain NOX (expressed as NO2) plus CO in excess 

of the applicable emissions limit specified in paragraphs (b)(1) 

through (3) of this section as determined on a 30-boiler 

operating day rolling average basis.

(1) For an affected facility which commenced construction or 

reconstruction, any gases that contain NOX plus CO in excess of 

either:

(i) 140 ng/J (1.1 lb/MWh) gross energy output; or

(ii) 150 ng/J (1.2 lb/MWh) net energy output.

(2) For an affected facility which commenced construction or 

reconstruction and that burns 75 percent or more coal refuse (by 

heat input) on a 12-month rolling average basis, any gases that 
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Page 799 of 1103

contain NOX plus CO in excess of either:

(i) 160 ng/J (1.3 lb/MWh) gross energy output; or

(ii) 170 ng/J (1.4 lb/MWh) net energy output.

(3) For an affected facility which commenced modification, any 

gases that contain NOX plus CO in excess of 190 ng/J (1.5 lb/MWh) 

gross energy output.

17. Section 60.47Da is amended as follows:

a. By revising paragraph (c).

b. By adding paragraph (f).

c. By adding paragraph (g).

d. By adding paragraph (h).

e. By adding paragraph (i).

Section 60.47Da Commercial demonstration permit.

* * * * *

(c) An owner or operator of an affected facility that uses 

fluidized bed combustion (atmospheric or pressurized) and who is 

issued a commercial demonstration permit by the Administrator is 

not subject to the SO2 emission reduction requirements under 

§60.43Da(a) but must, as a minimum, reduce SO2 emissions to 15 

percent of the potential combustion concentration (85 percent 

reduction) on a 30-day rolling average basis and to less than 

520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average 

basis.
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* * * * *

(f) An owner or operator of an affected facility that uses a 

pressurized fluidized bed or a multi-pollutant emissions 

controls system who is issued a commercial demonstration permit 

by the Administrator is not subject to the total PM emission 

reduction requirements under §60.42Da but must, as a minimum, 

reduce PM emissions to less than 6.4 ng/J (0.015 lb/MMBtu) heat 

input.

(g) An owner or operator of an affected facility that uses a 

pressurized fluidized bed or a multi-pollutant emissions 

controls system who is issued a commercial demonstration permit 

by the Administrator is not subject to the SO2 standards or 

emission reduction requirements under §60.43Da but must, as a 

minimum, reduce SO2 emissions to 5 percent of the potential 

combustion concentration (95 percent reduction) or to less than 

180 ng/J (1.4 lb/MWh) gross energy output on a 30-boiler 

operating day rolling average basis.

(h) An owner or operator of an affected facility that uses a 

pressurized fluidized bed or a multi-pollutant emissions control

system or advanced combustion controls who is issued a 

commercial demonstration permit by the Administrator is not 

subject to the NOX standards or emission reduction requirements 

under §60.44Da but must, as a minimum, reduce NOX emissions to 
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Page 801 of 1103

less than 130 ng/J (1.0 lb/MWh) or the combined NOX plus CO 

emissions to less than 180 ng/J (1.4 lb/MWh) gross energy output 

on a 30-boiler operating day rolling average basis.

(i) Commercial demonstration permits may not exceed the 

following equivalent MW electrical generation capacity for any 

one technology category listed in the following table.

Technology Pollutant

Equivalent Electrical 

Capacity 

(MW electrical output)

Multi-pollutant Emission 

Control SO2 1,000

Multi-pollutant Emission 

Control NOX 1,000

Multi-pollutant Emission 

Control PM 1,000

Pressurized Fluidized Bed 

Combustion SO2 1,000

Pressurized Fluidized Bed 

Combustion NOX 1,000

Pressurized Fluidized Bed 

Combustion PM 1,000

Advanced Combustion Controls NOX 1,000

18. Section 60.48Da is amended as follows:

a. By revising paragraphs (a) through (g).

b. By revising paragraph (i).

c. By revising paragraph (k)(1)(i).

d. By revising paragraph (k)(1)(ii).

e. By revising paragraph (k)(2)(i).

f. By revising paragraph (k)(2)(iv).

g. By removing and reserving paragraph (l).
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Page 802 of 1103

h. By revising paragraph (m).

i. By revising paragraph (n).

j. By revising paragraph (p).

k. By adding paragraph (r).

l. By adding paragraph (s).

Section 60.48Da Compliance provisions.

(a) For affected facilities for which construction, 

modification, or reconstruction commenced before May 4, 2011, 

the applicable PM emissions limit and opacity standard under 

§60.42Da, SO2 emissions limit under §60.43Da, and NOX emissions 

limit under §60.44Da apply at all times except during periods of 

startup, shutdown, or malfunction. For affected facilities for 

which construction, modification, or reconstruction commenced 

after May 3, 2011, the applicable SO2 emissions limit under 

§60.43Da, NOX emissions limit under §60.44Da, and NOX plus CO 

emissions limit under §60.45Da apply at all times. The 

applicable PM emissions limit and opacity standard under 

§60.42Da apply at all times except during periods of startup and 

shutdown.

(b) After the initial performance test required under §60.8, 

compliance with the applicable SO2 emissions limit and percentage 

reduction requirements under §60.43Da, NOX emissions limit under 

§60.44Da, and NOX plus CO emissions limit under §60.45Da is based 
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Page 803 of 1103

on the average emission rate for 30 successive boiler operating 

days. A separate performance test is completed at the end of 

each boiler operating day after the initial performance test, 

and a new 30-boiler operating day rolling average emission rate 

for both SO2, NOX or NOX plus CO as applicable, and a new percent 

reduction for SO2 are calculated to demonstrate compliance with 

the standards.

(c) For the initial performance test required under §60.8, 

compliance with the applicable SO2 emissions limits and 

percentage reduction requirements under §60.43Da, the NOX 

emissions limits under §60.44Da, and the NOX plus CO emissions 

limits under §60.45Da is based on the average emission rates for 

SO2, NOX, CO, and percent reduction for SO2 for the first 30 

successive boiler operating days. The initial performance test 

is the only test in which at least 30 days prior notice is 

required unless otherwise specified by the Administrator. The 

initial performance test is to be scheduled so that the first 

boiler operating day of the 30 successive boiler operating days 

is completed within 60 days after achieving the maximum 

production rate at which the affected facility will be operated, 

but not later than 180 days after initial startup of the 

facility.

(d) For affected facilities for which construction, 
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modification, or reconstruction commenced before May 4, 2011, 

compliance with applicable 30-boiler operating day rolling 

average SO2 and NOX emissions limits is determined by calculating 

the arithmetic average of all hourly emission rates for SO2 and 

NOX for the 30 successive boiler operating days, except for data 

obtained during startup, shutdown, or malfunction. For affected 

facilities for which construction, modification, or 

reconstruction commenced after May 3, 2011, compliance with 

applicable 30-boiler operating day rolling average SO2 and NOX

emissions limits is determined by dividing the sum of the SO2 and 

NOX emissions for the 30 successive boiler operating days divided 

by the sum of the gross energy output or net energy output, as 

applicable, for the 30 successive boiler operating days.

(e) For affected facilities for which construction, 

modification, or reconstruction commenced before May 4, 2011, 

compliance with applicable SO2 percentage reduction requirements 

is determined based on the average inlet and outlet SO2 emission 

rates for the 30 successive boiler operating days. For affected 

facilities for which construction, modification, or 

reconstruction commenced after May 3, 2011, compliance with 

applicable SO2 percentage reduction requirements is determined 

based on the “as fired” total potential emissions and the total 

outlet SO2 emissions for the 30 successive boiler operating days.
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(f) For affected facilities for which construction, 

modification, or reconstruction commenced before May 4, 2011, 

compliance with applicable daily average PM emissions limits is 

determined by calculating the arithmetic average of all hourly 

emission rates for PM each boiler operating day, except for data 

obtained during startup, shutdown, and malfunction. Daily 

averages are only calculated for boiler operating days that have 

non-out-of-control data for at least 18 hours of unit operation 

during which the standard applies. Instead, all of the non-outof-control hourly emission rates of the operating day(s) not 

meeting the minimum 18 hours non-out-of-control data daily 

average requirement are averaged with all of the non-out-ofcontrol hourly emission rates of the next boiler operating day 

with 18 hours or more of non-out-of-control PM CEMS data to 

determine compliance. For affected facilities for which 

construction, modification, or reconstruction commenced after 

May 3, 2011, compliance with applicable daily average PM 

emissions limits is determined by dividing the sum of the PM 

emissions for the 30 successive boiler operating days by the sum 

of the gross useful output or net energy output, as applicable, 

for the 30 successive boiler operating days. 

(g) For affected facilities for which construction, 

modification, or reconstruction commenced after May 3, 2011, 
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compliance with applicable 30-boiler operating day rolling 

average NOX plus CO emissions limit is determined by dividing the 

sum of the NOX plus CO emissions for the 30 successive boiler 

operating days by the sum of the gross energy output or net 

energy output, as applicable, for the 30 successive boiler 

operating days.

* * * * *

i) Compliance provisions for sources subject to §60.44Da(d)(1), 

(e)(1), (e)(2)(i), (e)(3)(i), (f), or (g). The owner or operator 

shall calculate NOX emissions as 1.194 × 10−7 lb/scf-ppm times the 

average hourly NOX output concentration in ppm (measured 

according to the provisions of §60.49Da(c)), times the average 

hourly flow rate (measured in scfh, according to the provisions 

of §60.49Da(l) or §60.49Da(m)), divided by the average hourly 

gross energy output (measured according to the provisions of 

§60.49Da(k)) or the average hourly net energy output, as 

applicable. Alternatively, for oil-fired and gas-fired units, NOX 

emissions may be calculated by multiplying the hourly NOX 

emission rate in lb/MMBtu (measured by the CEMS required under 

§60.49Da(c) and (d)), by the hourly heat input rate (measured 

according to the provisions of §60.49Da(n)), and dividing the 

result by the average gross energy output (measured according to 

the provisions of §60.49Da(k)) or the average hourly net energy 
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output, as applicable.

(k) * * *

(1) * * *

(i) The emission rate (E) of NOX shall be computed using Equation 

2 in this section:

E =

(Csg × Qsg) − (Cte × Qte)

(Osg × h)

(Eq. 2)

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/MWh) 

gross energy output;

Csg = Average hourly concentration of NOX exiting the steam 

generating unit, ng/dscm (lb/dscf);

Cte = Average hourly concentration of NOX in the turbine exhaust 

upstream from duct burner, ng/dscm (lb/dscf);

Qsg = Average hourly volumetric flow rate of exhaust gas from 

steam generating unit, dscm/h (dscf/h);

Qte = Average hourly volumetric flow rate of exhaust gas from 

combustion turbine, dscm/h (dscf/h);

Osg = Average hourly gross energy output from steam generating 

unit, J/h (MW); and

h = Average hourly fraction of the total heat input to the steam 

generating unit derived from the combustion of fuel in the 

affected duct burner.

* * * * *

(2) * * *

(i) The emission rate (E) of NOX shall be computed using Equation 

3 in this section:

E =

(Csg × Qsg)

Occ

(Eq. 3)

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/MWh) 

gross energy output;
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Csg = Average hourly concentration of NOX exiting the steam 

generating unit, ng/dscm (lb/dscf);

Qsg = Average hourly volumetric flow rate of exhaust gas from 

steam generating unit, dscm/h (dscf/h); and

Occ = Average hourly gross energy output from entire combined 

cycle unit, J/h (MW).

* * * * *

(iv) The owner or operator may, in lieu of installing, 

operating, and recording data from the continuous flow

monitoring system specified in §60.49Da(l), determine the mass 

rate (lb/h) of NOX emissions by installing, operating, and 

maintaining continuous fuel flowmeters following the appropriate 

measurements procedures specified in appendix D of part 75 of 

this chapter. If this compliance option is selected, the 

emission rate (E) of NOX shall be computed using Equation 4 in 

this section:

E =

(ERsg × Hcc)

Occ

(Eq. 4)

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/MWh) 

gross energy output;

ERsg = Average hourly emission rate of NOX exiting the steam 

generating unit heat input calculated using appropriate F factor 

as described in Method 19 of appendix A of this part, ng/J 

(lb/MMBtu);

Hcc = Average hourly heat input rate of entire combined cycle 

unit, J/h (MMBtu/h); and

Occ = Average hourly gross energy output from entire combined 

cycle unit, J/h (MW).

* * * * *

(m) Compliance provisions for sources subject to
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§60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), 

(j)(3)(i), (l)(1)(i), (l)(1)(ii), or (l)(2). The owner or 

operator shall calculate SO2 emissions as 1.660 × 10–7lb/scf-ppm 

times the average hourly SO2 output concentration in ppm 

(measured according to the provisions of §60.49Da(b)), times the 

average hourly flow rate (measured according to the provisions 

of §60.49Da(l) or §60.49Da(m)), divided by the average hourly 

gross energy output (measured according to the provisions of 

§60.49Da(k)) or the average hourly net energy output, as 

applicable. Alternatively, for oil-fired and gas-fired units, SO2 

emissions may be calculated by multiplying the hourly SO2 

emission rate (in lb/MMBtu), measured by the CEMS required under 

§60.49Da, by the hourly heat input rate (measured according to 

the provisions of §60.49Da(n)), and dividing the result by the 

average gross energy output (measured according to the 

provisions of §60.49Da(k)) or the average hourly net energy 

output, as applicable.

(n) Compliance provisions for sources subject to §60.42Da(c)(1) 

or (e). The owner or operator shall calculate PM emissions by 

multiplying the average hourly PM output concentration (measured 

according to the provisions of §60.49Da(t)), by the average 

hourly flow rate (measured according to the provisions of 

§60.49Da(l) or §60.49Da(m)), and dividing by the average hourly 
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gross energy output (measured according to the provisions of 

§60.49Da(k)) or the average hourly net energy output, as 

applicable.

* * * * *

(p) * * *

(5) At a minimum, non-out-of-control CEMS hourly averages shall 

be obtained for 75 percent of all operating hours on a 30-boiler 

operating day rolling average basis. Beginning on January 1, 

2012, non-out-of-control CEMS hourly averages shall be obtained 

for 90 percent of all operating hours on a 30-boiler operating 

day rolling average basis.

(i) At least two data points per hour shall be used to calculate 

each 1-hour arithmetic average.

(ii) [Reserved]

* * * * *

(7) All non-out-of-control CEMS data shall be used in 

calculating average emission concentrations even if the minimum 

CEMS data requirements of paragraph (j)(5) of this section are 

not met.

(8) When PM emissions data are not obtained because of CEMS 

breakdowns, repairs, calibration checks, and zero and span 

adjustments, emissions data shall be obtained by using other 

monitoring systems as approved by the Administrator or EPA 
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Reference Method 19 of appendix A of this part to provide, as 

necessary, non-out-of-control emissions data for a minimum of 90 

percent (only 75 percent is required prior to January 1, 2012) 

of all operating hours per 30-boiler operating day rolling 

average.

* * * * *

(r) Compliance provisions for sources subject to §60.45Da. To 

determine compliance with the NOX plus CO emissions limit, the 

owner or operator shall use the procedures specified in 

paragraphs (r)(1) through (3) of this section.

(1) Calculate NOX emissions as 1.194 × 10−7 lb/scf-ppm times the 

average hourly NOX output concentration in ppm (measured 

according to the provisions of §60.49Da(c)), times the average 

hourly flow rate (measured in scfh, according to the provisions 

of §60.49Da(l) or §60.49Da(m)), divided by the average hourly 

gross energy output (measured according to the provisions of 

§60.49Da(k)) or the average hourly net energy output, as 

applicable.

(2) Calculate CO emissions by multiplying the average hourly CO 

output concentration (measured according to the provisions of 

§60.49Da(u), by the average hourly flow rate (measured according 

to the provisions of §60.49Da(l) or §60.49Da(m)), and dividing 

by the average hourly gross energy output (measured according to 
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the provisions of §60.49Da(k)) or the average hourly net energy 

output, as applicable.

(3) Calculate NOX plus CO emissions by summing the NOX emissions 

results from paragraph (r)(1) of this section plus the CO

emissions results from paragraph (r)(2) of this section.

(s) Affirmative defense for exceedance of emissions limit during 

malfunction. In response to an action to enforce the standards 

set forth in paragraph §§60.42Da, 60.43Da, 60.44Da, and 60.45Da, 

you may assert an affirmative defense to a claim for civil 

penalties for exceedances of such standards that are caused by 

malfunction, as defined at 40 CFR 60.2. Appropriate penalties 

may be assessed, however, if you fail to meet your burden of 

proving all of the requirements in the affirmative defense as 

specified in paragraphs (s)(1) and (2) of this section. The 

affirmative defense shall not be available for claims for 

injunctive relief.

(1) To establish the affirmative defense in any action to 

enforce such a limit, you must timely meet the notification 

requirements in paragraph (s)(2) of this section, and must prove 

by a preponderance of evidence that:

(i) The excess emissions:

(A) Were caused by a sudden, infrequent, and unavoidable failure 

of air pollution control and monitoring equipment, process 
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equipment, or a process to operate in a normal or usual manner;

and

(B) Could not have been prevented through careful planning, 

proper design, or better operation and maintenance practices; 

and

(C) Did not stem from any activity or event that could have been 

foreseen and avoided, or planned for; and

(D) Were not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; and

(ii) Repairs were made as expeditiously as possible when the 

applicable emissions limits were being exceeded. Off-shift and 

overtime labor were used, to the extent practicable to make 

these repairs; and

(iii) The frequency, amount, and duration of the excess 

emissions (including any bypass) were minimized to the maximum 

extent practicable during periods of such emissions; and

(iv) If the excess emissions resulted from a bypass of control 

equipment or a process, then the bypass was unavoidable to 

prevent loss of life, personal injury, or severe property 

damage; and

(v) All possible steps were taken to minimize the impact of the 

excess emissions on ambient air quality, the environment, and 

human health; and
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(vi) All emissions monitoring and control systems were kept in 

operation if at all possible, consistent with safety and good 

air pollution control practices; and

(vii) All of the actions in response to the excess emissions 

were documented by properly signed, contemporaneous operating 

logs; and

(viii) At all times, the facility was operated in a manner 

consistent with good practices for minimizing emissions; and

(ix) A written root cause analysis has been prepared, the 

purpose of which is to determine, correct, and eliminate the 

primary causes of the malfunction and the excess emissions 

resulting from the malfunction event at issue. The analysis 

shall also specify, using best monitoring methods and 

engineering judgment, the amount of excess emissions that were 

the result of the malfunction.

(2) Notification. The owner or operator of the affected source 

experiencing an exceedance of its emission limit(s) during a 

malfunction shall notify the Administrator by telephone or 

facsimile (FAX) transmission as soon as possible, but no later 

than two business days after the initial occurrence of the 

malfunction or, if it is not possible to determine within two 

business days whether the malfunction caused or contributed to 

an exceedance, no later than two business days after the owner 
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or operator knew or should have known that the malfunction 

caused or contributed to an exceedance, but, in no event later 

than two business days after the end of the averaging period, if 

it wishes to avail itself of an affirmative defense to civil 

penalties for that malfunction. The owner or operator seeking to 

assert an affirmative defense shall also submit a written report 

to the Administrator within 45 days of the initial occurrence of 

the exceedance of the standard in §63.9991 to demonstrate, with 

all necessary supporting documentation, that it has met the 

requirements set forth in paragraph (s)(1) of this section. The

owner or operator may seek an extension of this deadline for up 

to 30 additional days by submitting a written request to the 

Administrator before the expiration of the 45 day period. Until 

a request for an extension has been approved by the 

Administrator, the owner or operator is subject to the 

requirement to submit such report within 45 days of the initial 

occurrence of the exceedance.

19. Section 60.49Da is amended as follows:

a. By revising paragraph (a).

b. By revising paragraph (b).

c. By revising paragraph (e).

d. By revising paragraph (k).

e. By revising paragraph (l).
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f. By removing and reserving paragraph (p).

g. By removing and reserving paragraph (q).

h. By removing and reserving paragraph (r).

i. By revising paragraph (t).

j. By revising paragraph (u).

k. By revising paragraph (v).

Section 60.49Da Emission monitoring.

(a) * * * 

(1) Except as provided for in paragraphs (a)(2) and (4) of this 

section, the owner or operator of an affected facility subject 

to an opacity standard, shall install, calibrate, maintain, and 

operate a COMS, and record the output of the system, for 

measuring the opacity of emissions discharged to the atmosphere. 

If opacity interference due to water droplets exists in the 

stack (for example, from the use of an FGD system), the opacity 

is monitored upstream of the interference (at the inlet to the 

FGD system). If opacity interference is experienced at all 

locations (both at the inlet and outlet of the SO2 control 

system), alternate parameters indicative of the PM control 

system’s performance and/or good combustion are monitored 

(subject to the approval of the Administrator).

(2) As an alternative to the monitoring requirements in 

paragraph (a)(1) of this section, an owner or operator of an 
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affected facility that meets the conditions in either paragraph 

(a)(2)(i), (ii), (iii), or (iv) of this section may elect to 

monitor opacity as specified in paragraph (a)(3) of this 

section.

(i) The affected facility uses a fabric filter (baghouse) to 

meet the standards in §60.42Da and a bag leak detection system 

is installed and operated according to the requirements in 

paragraphs §60.48Da(o)(4)(i) through (v);

(ii) The affected facility burns only gaseous or liquid fuels 

(excluding residual oil) with potential SO2 emissions rates of 26 

ng/J (0.060 lb/MMBtu) or less, and does not use a postcombustion technology to reduce emissions of SO2 or PM;

(iii) The affected facility meets all of the conditions 

specified in paragraphs (a)(2)(iii)(A) through (C) of this 

section.

(A) No post-combustion technology (except a wet scrubber) is 

used for reducing PM, SO2, or CO emissions;

(B) Only natural gas, gaseous fuels, or fuel oils that contain 

less than or equal to 0.30 weight percent sulfur are burned; and

(C) Emissions of CO discharged to the atmosphere are maintained 

at levels less than or equal to 1.4 lb/MWh on a boiler operating 

day average basis as demonstrated by the use of a CEMS measuring 

CO emissions according to the procedures specified in paragraph 
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(u) of this section; or

(iv) The affected facility uses an ESP and uses an ESP 

predictive model to monitor the performance of the ESP developed 

in accordance and operated according to the most current 

requirements in section §60.48Da of this part.

(3) The owner or operators of an affected facility that meets 

the conditions in paragraph (a)(2) of this section may, as an 

alternative to using a COMS, elect to monitor visible emissions 

using the applicable procedures specified in paragraphs 

(a)(3)(i) through (iv) of this section. The opacity performance 

test requirement in paragraph (a)(3)(i) must be conducted by 

April 29, 2011, within 45 days after stopping use of an existing 

COMS, or within 180 days after initial startup of the facility, 

whichever is later.

(i) * * *

(ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this 

section, the owner or operator shall conduct subsequent Method 9 

of appendix A–4 of this part performance tests using the 

procedures in paragraph (a)(3)(i) of this section according to 

the applicable schedule in paragraphs (a)(3)(ii)(A) through 

(a)(3)(ii)(C) of this section, as determined by the most recent 

Method 9 of appendix A–4 of this part performance test results.

(A) If the maximum 6-minute average opacity is less than or 
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equal to 5 percent,, a subsequent Method 9 of appendix A–4 of 

this part performance test must be completed within 12 calendar 

months from the date that the most recent performance test was 

conducted or within 45 days of the next day that fuel with an 

opacity standard is combusted, whichever is later;

(B) If the maximum 6-minute average opacity is greater than 5 

percent but less than or equal to 10 percent, a subsequent 

Method 9 of appendix A–4 of this part performance test must be 

completed within 3 calendar months from the date that the most 

recent performance test was conducted or within 45 days of the 

next day that fuel with an opacity standard is combusted, 

whichever is later; or

(C) If the maximum 6-minute average opacity is greater than 10 

percent, a subsequent Method 9 of appendix A–4 of this part 

performance test must be completed within 45 calendar days from 

the date that the most recent performance test was conducted.

(iii) * * *

(A) * * *

(B) If no visible emissions are observed for 10 operating days 

during which an opacity standard is applicable, observations can 

be reduced to once every 7 operating days during which an 

opacity standard is applicable. If any visible emissions are 

observed, daily observations shall be resumed.
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(iv) * * *

(4) An owner or operator of an affected facility that is subject 

to an opacity standard under §60.42a(b) is not required to 

operate a COMS provided that affected facility meets the 

conditions in either paragraph (4)(i) or (ii) of this section.

(i) The affected facility combusts only gaseous fuels and/or 

liquid fuels (excluding residue oil) with a potential SO2

emissions rate no greater than 26 ng/J (0.060 lb/MMBtu), and the 

unit operates according to a written site-specific monitoring 

plan approved by the permitting authority. This monitoring plan 

must include procedures and criteria for establishing and 

monitoring specific parameters for the affected facility 

indicative of compliance with the opacity standard. For testing 

performed as part of this site-specific monitoring plan, the 

permitting authority may require as an alternative to the 

notification and reporting requirements specified in §§60.8 and 

60.11 that the owner or operator submit any deviations with the 

excess emissions report required under §60.51a(d).

(ii) The owner or operator of the affected facility installs, 

calibrates, operates, and maintains a particulate matter 

continuous parametric monitoring system (PM CPMS) according to 

the requirements specified in subpart UUUUU of part 63.

(b) The owner or operator of an affected facility shall install, 
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calibrate, maintain, and operate a CEMS, and record the output 

of the system, for measuring SO2 emissions, except where natural 

gas and/or liquid fuels (excluding residual oil) with potential 

SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less are the 

only fuels combusted, as follows:

(1) * * *

(2) For a facility that qualifies under the numerical limit 

provisions of §60.43Da, SO2 emissions are only monitored as 

discharged to the atmosphere.

* * * * *

(e) The CEMS under paragraphs (b), (c), and (d) of this section 

are operated and data recorded during all periods of operation 

of the affected facility including periods of startup, shutdown,

and malfunction, except for CEMS breakdowns, repairs, 

calibration checks, and zero and span adjustments.

* * * * *

(k) The procedures specified in paragraphs (k)(1) through (3) of 

this section shall be used to determine gross energy output for 

sources demonstrating compliance with an output-based standard.

(1) * * *

(2) * * *

(3) For an affected facility generating process steam in 

combination with electrical generation, the gross energy output 
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is determined according to the definition of “gross energy 

output” specified in §60.41Da that is applicable to the affected 

facility.

(l) The owner or operator of an affected facility demonstrating 

compliance with an output-based standard shall install, certify, 

operate, and maintain a continuous flow monitoring system 

meeting the requirements of Performance Specification 6 of 

appendix B of this part and the calibration drift (CD)

assessment, relative accuracy test audit (RATA), and reporting 

provisions of procedure 1 of appendix F of this part, and record 

the output of the system, for measuring the volumetric flow rate

of exhaust gases discharged to the atmosphere; or

* * * * * 

(t) The owner or operator of an affected facility demonstrating 

compliance with the output-based emissions limitation under 

§60.42Da shall install, certify, operate, and maintain a CEMS 

for measuring PM emissions according to the requirements of 

paragraph (v) of this section. An owner or operator of an 

affected facility demonstrating compliance with the input-based 

emissions limit in §60.42Da may install, certify, operate, and 

maintain a CEMS for measuring PM emissions according to the 

requirements of paragraph (v) of this section.

(u) * * *
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(1) * * *

(iii) At a minimum, non-out-of-control 1-hour CO emissions 

averages must be obtained for at least 90 percent of the 

operating hours on a 30-boiler operating day rolling average 

basis. The 1-hour averages are calculated using the data points 

required in §60.13(h)(2).

* * * * *

(v) * * *

* * * * *

(4) As of January 1, 2012, and within 90 days after the date of 

completing each performance test, as defined in §68, conducted 

to demonstrate compliance with this subpart, you must submit 

relative accuracy test audit (i.e., reference method) data and 

performance test (i.e., compliance test) data, except opacity 

data, electronically to EPA’s Central Data Exchange (CDX) by 

using the Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/ert tool.html/) or other 

compatible electronic spreadsheet. Only data collected using 

test methods compatible with ERT are subject to this requirement 

to be submitted electronically into EPA’s WebFire database.

20. Section 60.50Da is amended as follows:

a. By revising paragraph (b).

b. By removing paragraph (g).
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c. By removing paragraph (h).

d. By removing paragraph (i).

Section 60.50Da Compliance determination procedures and methods.

* * * * *

(b) In conducting the performance tests to determine compliance 

with the PM emissions limits in §60.42Da, the owner or operator 

shall meet the requirements specified in paragraphs (b)(1) 

through (3) of this section.

(1) The owner or operator shall measure filterable PM to 

determine compliance with the applicable PM emissions limit in 

§60.42Da as specified in paragraphs (b)(1)(i) through (iii) of 

this section.

(i) The dry basis F factor (O2) procedures in Method 19 of 

appendix A of this part shall be used to compute the emission 

rate of PM.

(ii) For the PM concentration, Method 5 of appendix A of this 

part shall be used for an affected facility that does not use a 

wet FGD. For an affected facility that uses a wet FGD, Method 5B 

of appendix A of this part shall be used downstream of the wet 

FGD.

(A) The sampling time and sample volume for each run shall be at 

least 120 minutes and 1.70 dscm (60 dscf). The probe and filter 

holder heating system in the sampling train may be set to 
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provide an average gas temperature of no greater than 160±14 °C 

(320±25 °F).

(B) For each particulate run, the emission rate correction 

factor, integrated or grab sampling and analysis procedures of 

Method 3B of appendix A of this part shall be used to determine 

the O2 concentration. The O2 sample shall be obtained 

simultaneously with, and at the same traverse points as, the 

particulate run. If the particulate run has more than 12 

traverse points, the O2 traverse points may be reduced to 12 

provided that Method 1 of appendix A of this part is used to 

locate the 12 O2 traverse points. If the grab sampling procedure 

is used, the O2 concentration for the run shall be the arithmetic 

mean of the sample O2 concentrations at all traverse points.

(2) In conjunction with a performance test performed according 

to the requirements in paragraph (b)(1) of this section, the 

owner or operator of an affected facility for which 

construction, reconstruction, or modification commenced after 

May 3, 2011, shall measure condensable PM using Method 202 of 

appendix M of part 51.

(3) Method 9 of appendix A of this part and the procedures in 

§60.11 shall be used to determine opacity.

* * * * *

21. Section 60.51Da is amended as follows:
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a. By revising paragraph (a).

b. By revising paragraph (b).

c. By revising paragraph (d).

d. By removing and reserving paragraph (g).

e. By revising paragraph (k).

Section 60.51 Da Reporting requirements.

(a) For SO2, NOX, PM, and NOX plus CO emissions, the performance 

test data from the initial and subsequent performance test and 

from the performance evaluation of the continuous monitors 

(including the transmissometer) must be reported to the 

Administrator.

(b) * * *

(1) – (4) * * *

(5) Identification of the times when emissions data have been 

excluded from the calculation of average emission rates because 

of startup, shutdown, or malfunction.

* * * * *

(d) In addition to the applicable requirements in §60.7, the 

owner or operator of an affected facility subject to the opacity 

limits in §60.43c(c) and conducting performance tests using 

Method 9 of appendix A-4 of this part shall submit excess 

emission reports for any excess emissions from the affected 

facility that occur during the reporting period and maintain 
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records according to the requirements specified in paragraphs 

(d)(1) through (3) of this section.

(1) For each performance test conducted using Method 9 of 

appendix A-4 of this part, the owner or operator shall keep the 

records including the information specified in paragraphs 

(c)(1)(i) through (iii) of this section.

(i) Dates and time intervals of all opacity observation periods;

(ii) Name, affiliation, and copy of current visible emission 

reading certification for each visible emission observer 

participating in the performance test; and

(iii) Copies of all visible emission observer opacity field data 

sheets.

* * * * *

(k) The owner or operator of an affected facility may submit 

electronic quarterly reports for SO2 and/or NOX and/or opacity in 

lieu of submitting the written reports required under paragraphs 

(b), (g), and (i) of this section. The format of each quarterly 

electronic report shall be coordinated with the permitting 

authority. The electronic report(s) shall be submitted no later 

than 30 days after the end of the calendar quarter and shall be 

accompanied by a certification statement from the owner or 

operator, indicating whether compliance with the applicable 

emission standards and minimum data requirements of this subpart 
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was achieved during the reporting period.

22. Section 60.52Da is amended by removing and reserving 

paragraph (a).

Section 60.52Da Recordkeeping requirements.

* * * * *

Subpart Db-—[Amended]

23. Section 60.40b is amended as follows:

a. By revising paragraph (c).

b. By revising paragraph (h).

c. By revising paragraph (i).

d. By adding paragraph (1).

e. By adding paragraph (m).

Section 60.40b Applicability and delegation of authority.

* * * * *

(c) Affected facilities that also meet the applicability 

requirements under subpart J or subpart Ja of this part are 

subject to the PM and NOX standards under this subpart and the 

SO2 standards under subpart J or subpart Ja of this part, as 

applicable.

* * * * *

(h) Any affected facility that meets the applicability 

requirements and is subject to subpart Ea, subpart Eb, subpart 

AAAA, or subpart CCCC of this part is not subject to this 
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subpart. 

(i) Affected facilities (i.e., heat recovery steam generators) 

that are associated with stationary combustion turbines and that 

meet the applicability requirements of subpart KKKK of this part 

are not subject to this subpart. This subpart will continue to 

apply to all other affected facilities (i.e. heat recovery steam 

generators with duct burners) that are capable of combusting 

more than 29 MW (100 MMBtu/h) heat input of fossil fuel. If the 

affected facility (i.e. heat recovery steam generator) is 

subject to this subpart, only emissions resulting from 

combustion of fuels in the steam generating unit are subject to 

this subpart. (The stationary combustion turbine emissions are 

subject to subpart GG or KKKK, as applicable, of this part.)

* * * * *

(l) Affected facilities that also meet the applicability 

requirements under subpart BB (Standards of Performance for 

Kraft Pulp Mills) are subject to the SO2 and NOX standards under 

this subpart and the PM standards under subpart BB.

(m) Temporary boilers are not subject to this subpart.

* * * * *

24. Section 60.41b is amended by revising the definition of 

“distillate oil”, and adding the definition of “temporary 

boiler” to read as follows:
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Section 60.41b Definitions.

* * * * *

Distillate oil means fuel oils that contain 0.05 weight percent 

nitrogen or less and comply with the specifications for fuel oil 

numbers 1 and 2, as defined by the American Society of Testing 

and Materials in ASTM D396 (incorporated by reference, see 

§60.17), diesel fuel oil numbers 1 and 2, as defined by the 

American Society for Testing and Materials in ASTM D975 

(incorporated by reference, see §60.17), kerosine, as defined by 

the American Society of Testing and Materials in ASTM D3699 

(incorporated by reference, see §60.17), biodiesel as defined by 

the American Society of Testing and Materials in ASTM D6751 

(incorporated by reference, see §60.17), or biodiesel blends as 

defined by the American Society of Testing and Materials in ASTM 

D7467 (incorporated by reference, see §60.17).

* * * * *

Temporary boiler means any gaseous or liquid fuel-fired steam 

generating unit that is designed to, and is capable of, being 

carried or moved from one location to another by means of, for 

example, wheels, skids, carrying handles, dollies, trailers, or 

platforms. A steam generating unit is not a temporary boiler if 

any one of the following conditions exists:

(1) The equipment is attached to a foundation.
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(2) The steam generating unit or a replacement remains at a 

location for more than 180 consecutive days. Any temporary 

boiler that replaces a temporary boiler at a location and 

performs the same or similar function will be included in 

calculating the consecutive time period.

(3) The equipment is located at a seasonal facility and operates 

during the full annual operating period of the seasonal 

facility, remains at the facility for at least 2 years, and 

operates at that facility for at least 3 months each year.

(4) The equipment is moved from one location to another in an 

attempt to circumvent the residence time requirements of this 

definition. 

* * * * *

25. Section 60.43b is amended by revising paragraph (f) to read 

as follows:

§60.43b Standard for particulate matter (PM).

* * * * *

(f) On and after the date on which the initial performance test 

is completed or is required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected 

facility that combusts coal, oil, wood, or mixtures of these 

fuels with any other fuels shall cause to be discharged into the 

atmosphere any gases that exhibit greater than 20 percent 
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opacity (6-minute average), except for one 6-minute period per 

hour of not more than 27 percent opacity. An owner or operator

of an affected facility that elects to install, calibrate, 

maintain, and operate a continuous emissions monitoring system 

(CEMS) for measuring PM emissions according to the requirements 

of this subpart and is subject to a federally enforceable PM 

limit of 0.030 lb/MMBtu or less is exempt from the opacity 

standard specified in this paragraph.

* * * * *

26. Section 60.44b is amended as follows:

a. The section heading for section 60.44Db is revised.

b. by revising paragraph (b).

c. By revising paragraph (c). 

d. By revising paragraph (d).

e By revising paragraph (e).

f. By revising paragraph (l).

Section 60.44b Standard for nitrogen oxides (NOX).

* * * * *

(b) Except as provided under paragraphs (k) and (l) of this 

section, on and after the date on which the initial performance 

test is completed or is required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected 

facility that simultaneously combusts mixtures of only coal, 
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oil, or natural gas shall cause to be discharged into the 

atmosphere from that affected facility any gases that contain NOX

in excess of a limit determined by the use of the following 

formula:

* * * * *

(c) Except as provided under paragraph (d) and (l) of this 

section, on and after the date on which the initial performance 

test is completed or is required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected 

facility that simultaneously combusts coal or oil, natural gas 

(or any combination of the three), and wood, or any other fuel 

shall cause to be discharged into the atmosphere any gases that 

contain NOX in excess of the emission limit for the coal, oil, 

natural gas (or any combination of the three), combusted in the 

affected facility, as determined pursuant to paragraph (a) or 

(b) of this section. This standard does not apply to an affected 

facility that is subject to and in compliance with a federally 

enforceable requirement that limits operation of the affected 

facility to an annual capacity factor of 10 percent (0.10) or 

less for coal, oil, natural gas (or any combination of the 

three).

(d) On and after the date on which the initial performance test 

is completed or is required to be completed under §60.8, 
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whichever date comes first, no owner or operator of an affected 

facility that simultaneously combusts natural gas and/or 

distillate oil with a potential SO2 emissions rate of 26 ng/J 

(0.060 lb/MMBtu) or less with wood, municipal-type solid waste, 

or other solid fuel, except coal, shall cause to be discharged 

into the atmosphere from that affected facility any gases that 

contain NOX in excess of 130 ng/J (0.30 lb/MMBtu) heat input 

unless the affected facility has an annual capacity factor for 

natural gas, distillate oil, or a mixture of these fuels of 10 

percent (0.10) or less and is subject to a federally enforceable 

requirement that limits operation of the affected facility to an 

annual capacity factor of 10 percent (0.10) or less for natural 

gas, distillate oil, or a mixture of these fuels.

(e) Except as provided under paragraph (l) of this section, on 

and after the date on which the initial performance test is 

completed or is required to be completed under §60.8, whichever 

date comes first, no owner or operator of an affected facility 

that simultaneously combusts only coal, oil, or natural gas with 

byproduct/waste shall cause to be discharged into the atmosphere 

any gases that contain NOX in excess of the emission limit 

determined by the following formula unless the affected facility 

has an annual capacity factor for coal, oil, and natural gas of 

10 percent (0.10) or less and is subject to a federally 
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enforceable requirement that limits operation of the affected 

facility to an annual capacity factor of 10 percent (0.10) or 

less:

* * * * *

(l) * * *

(1) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility 

combusts coal, oil, or natural gas (or any combination of the 

three), alone or with any other fuels. The affected facility is 

not subject to this limit if it is subject to and in compliance 

with a federally enforceable requirement that limits operation 

of the facility to an annual capacity factor of 10 percent 

(0.10) or less for coal, oil, and natural gas (or any 

combination of the three); or

* * * * *

27. Section 60.46b is amended by revising paragraph (j)(14) to 

read as follows:

Section 60.46b Compliance and performance test methods and 

procedures for particulate matter and nitrogen oxides.

* * * * *

(j) * * *

(14) As of January 1, 2012, and within 90 days after the date of 

completing each performance test, as defined in §68, conducted 

to demonstrate compliance with this subpart, you must submit 
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relative accuracy test audit (i.e., reference method) data and 

performance test (i.e., compliance test) data, except opacity 

data, electronically to EPA’s Central Data Exchange (CDX) by 

using the Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/ert tool.html/) or other 

compatible electronic spreadsheet. Only data collected using 

test methods compatible with ERT are subject to this requirement 

to be submitted electronically into EPA’s WebFIRE database.

28. Section 60.48b is amended as follows:

a. By revising paragraph (a).

b. By revising paragraph (j) introductory text.

c. By revising paragraph (j)(5).

d. By revising paragraph (j)(6).

e. By adding paragraph (j)(7).

f. By adding paragraph (l).

Section 60.48b Emission monitoring for particulate matter and 

nitrogen oxides.

(a) Except as provided in paragraph (j) of this section, the 

owner or operator of an affected facility subject to the opacity 

standard under §60.43b shall install, calibrate, maintain, and 

operate a continuous opacity monitoring systems (COMS) for 

measuring the opacity of emissions discharged to the atmosphere 

and record the output of the system. The owner or operator of an 
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affected facility subject to an opacity standard under §60.43b 

and meeting the conditions under paragraphs (j)(1), (2), (3), 

(4), (5), or (6) of this section who elects not to use a COMS 

shall conduct a performance test using Method 9 of appendix A–4 

of this part and the procedures in §60.11 to demonstrate 

compliance with the applicable limit in §60.43b by April 29, 

2011, within 45 days of stopping use of an existing COMS, or 

within 180 days after initial startup of the facility, whichever 

is later, and shall comply with either paragraphs (a)(1), 

(a)(2), or (a)(3) of this section. The observation period for 

Method 9 of appendix A-4 of this part performance tests may be 

reduced from 3 hours to 60 minutes if all 6-minute averages are 

less than 10 percent and all individual 15-second observations 

are less than or equal to 20 percent during the initial 60 

minutes of observation.

(1) * * *

(i) If no visible emissions are observed, a subsequent Method 9 

of appendix A–4 of this part performance test must be completed 

within 12 calendar months from the date that the most recent 

performance test was conducted or within 45 days of the next day 

that fuel with an opacity standard is combusted, whichever is 

later;

(ii) If visible emissions are observed but the maximum 6-minute 
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average opacity is less than or equal to 5 percent, a subsequent 

Method 9 of appendix A–4 of this part performance test must be 

completed within 6 calendar months from the date that the most 

recent performance test was conducted or within 45 days of the 

next day that fuel with an opacity standard is combusted, 

whichever is later;

(iii) If the maximum 6-minute average opacity is greater than 5 

percent but less than or equal to 10 percent, a subsequent 

Method 9 of appendix A–4 of this part performance test must be 

completed within 3 calendar months from the date that the most 

recent performance test was conducted or within 45 days of the 

next day that fuel with an opacity standard is combusted, 

whichever is later; or

(iv) * * *

(2) * * *

(i) * * *

(ii) If no visible emissions are observed for 10 operating days 

during which an opacity standard is applicable, observations can 

be reduced to once every 7 operating days during which an 

opacity standard is applicable. If any visible emissions are 

observed, daily observations shall be resumed.

* * * * *

(j) The owner or operator of an affected facility that meets the 
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conditions in either paragraph (j)(1), (2), (3), (4), (5), (6), 

or (7) of this section is not required to install or operate a 

COMS if:

* * * * *

(5) The affected facility uses a bag leak detection system to 

monitor the performance of a fabric filter (baghouse) according 

to the most current requirements in section §60.48Da of this 

part; or

(6) The affected facility uses an ESP as the primary PM control 

device and uses an ESP predictive model to monitor the 

performance of the ESP developed in accordance and operated 

according to the most current requirements in section §60.48Da 

of this part; or

(7) The affected facility burns only gaseous fuels or fuel oils 

that contain less than or equal to 0.30 weight percent sulfur 

and operates according to a written site-specific monitoring 

plan approved by the permitting authority. This monitoring plan 

must include procedures and criteria for establishing and 

monitoring specific parameters for the affected facility 

indicative of compliance with the opacity standard.

* * * * *

(l) An owner or operator of an affected facility that is subject 

to an opacity standard under §60.43b(f) is not required to 
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operate a COMS provided that the unit burns only gaseous fuels 

and/or liquid fuels (excluding residue oil) with a potential SO2

emissions rate no greater than 26 ng/J (0.060 lb/MMBtu), and the 

unit operates according to a written site-specific monitoring 

plan approved by the permitting authority is not required to 

operate a COMS. This monitoring plan must include procedures and 

criteria for establishing and monitoring specific parameters for 

the affected facility indicative of compliance with the opacity 

standard. For testing performed as part of this site-specific 

monitoring plan, the permitting authority may require as an 

alternative to the notification and reporting requirements 

specified in §§60.8 and 60.11 that the owner or operator submit 

any deviations with the excess emissions report required under 

§60.49b(h).

29. Section 60.49b is amended by revising paragraph (r) as 

follows.

§60.49b Reporting and recordkeeping requirements.

* * * * *

(r) * * *

(1) The owner or operator of an affected facility who elects to 

demonstrate that the affected facility combusts only very low 

sulfur oil, natural gas, wood, a mixture of these fuels, or any 

of these fuels (or a mixture of these fuels) in combination with 
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other fuels that are known to contain an insignificant amount of 

sulfur in §60.42b(j) or §60.42b(k) shall obtain and maintain at 

the affected facility fuel receipts (such as a current, valid 

purchase contract, tariff sheet, or transportation contract) 

from the fuel supplier that certify that the oil meets the 

definition of distillate oil and gaseous fuel meets the 

definition of natural gas as defined in §60.41b and the 

applicable sulfur limit. For the purposes of this section, the 

distillate oil need not meet the fuel nitrogen content 

specification in the definition of distillate oil. Reports shall 

be submitted to the Administrator certifying that only very low 

sulfur oil meeting this definition, natural gas, wood, and/or 

other fuels that are known to contain insignificant amounts of 

sulfur were combusted in the affected facility during the 

reporting period; or

* * * * *

Subpart Dc-—[Amended]

30. Section 60.40c is amended as follows:

a. By revising paragraph (a).

b. By revising paragraph (e).

c. By revising paragraph (f).

d. By revising paragraph (g).

e. By adding paragraph (h).
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f. By adding paragraph (i).

Section 60.40c Applicability and delegation of authority.

(a) Except as provided in paragraphs (d), (e), (f), and (g) of 

this section, the affected facility to which this subpart 

applies is each steam generating unit for which construction, 

modification, or reconstruction is commenced after June 9, 1989 

and that has a maximum design heat input capacity of 29 

megawatts (MW) (100 million British thermal units per hour 

(MMBtu/h)) or less, but greater than or equal to 2.9 MW (10 

MMBtu/h).

* * * * *

(e) Affected facilities (i.e. heat recovery steam generators and 

fuel heaters) that are associated with stationary combustion 

turbines and meet the applicability requirements of subpart KKKK 

of this part are not subject to this subpart. This subpart will 

continue to apply to all other heat recovery steam generators, 

fuel heaters, and other affected facilities that are capable of 

combusting more than or equal to 2.9 MW (10 MMBtu/h) heat input 

of fossil fuel but less than or equal to 29 MW (100 MMBtu/h) 

heat input of fossil fuel. If the heat recovery steam generator, 

fuel heater, or other affected facility is subject to this 

subpart, only emissions resulting from combustion of fuels in 

the steam generating unit are subject to this subpart. (The 
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stationary combustion turbine emissions are subject to subpart 

GG or KKKK, as applicable, of this part).

(f) Any affected facility that meets the applicability 

requirements of and is subject to subpart AAAA or subpart CCCC 

of this part is not subject to this subpart.

(g) Any facility that meets the applicability requirements and 

is subject to an EPA approved State or Federal section 

111(d)/129 plan implementing subpart BBBB of this part is not 

subject to this subpart.

(h) Affected facilities that also meet the applicability 

requirements under subpart J or subpart Ja of this part are 

subject to the PM and NOX standards under this subpart and the 

SO2 standards under subpart J or subpart Ja of this part, as 

applicable.

(i) Temporary boilers are not subject to this subpart.

31. Section 60.41c is amended as follows:

a. By removing the definition of “Cogeneration.”

b. By revising the definition of “Distillate oil.”

c. By adding a definition of “Temporary boiler.”

Section 60.41c Definitions.

* * * * *

Distillate oil means fuel oil that complies with the 

specifications for fuel oil numbers 1 or 2, as defined by the 
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American Society for Testing and Materials in ASTM D396 

(incorporated by reference, see §60.17), diesel fuel oil numbers 

1 or 2, as defined by the American Society for Testing and 

Materials in ASTM D975 (incorporated by reference, see §60.17), 

kerosine, as defined by the American Society of Testing and 

Materials in ASTM D3699 (incorporated by reference, see §60.17), 

biodiesel as defined by the American Society of Testing and 

Materials in ASTM D6751 (incorporated by reference, see §60.17), 

or biodiesel blends as defined by the American Society of 

Testing and Materials in ASTM D7467 (incorporated by reference, 

see §60.17).

* * * * *

Temporary boiler means a steam generating unit that combusts 

natural gas or distillate oil with a potential SO2 emissions rate 

no greater than 26 ng/J (0.060 lb/MMBtu), and the unit is 

designed to, and is capable of, being carried or moved from one 

location to another by means of, for example, wheels, skids, 

carrying handles, dollies, trailers, or platforms. A steam 

generating unit is not a temporary boiler if any one of the 

following conditions exists:

(1) The equipment is attached to a foundation.

(2) The steam generating unit or a replacement remains at a 

location for more than 180 consecutive days. Any temporary 
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boiler that replaces a temporary boiler at a location and 

performs the same or similar function will be included in 

calculating the consecutive time period.

(3) The equipment is located at a seasonal facility and operates 

during the full annual operating period of the seasonal 

facility, remains at the facility for at least 2 years, and 

operates at that facility for at least 3 months each year.

(4) The equipment is moved from one location to another in an 

attempt to circumvent the residence time requirements of this 

definition. 

* * * * *

32. Section 60.42c is amended as follows:

a. By revising paragraph (c)(1) and (3).

b. By revising paragraph (d).

c. By revising paragraph (e)(1)(ii).

d. By revising paragraph (h) introductory text.

e. By revising paragraph (h)(3).

f. By adding paragraph (h)(4).

Section 60.42c Standard for sulfur dioxide (SO2).

* * * * *

(c) * * *

(1) Affected facilities that have a heat input capacity of 22 MW 

(75 MMBtu/h) or less;
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(2) * * *

(3) Affected facilities located in a noncontinental area; or

* * * * *

(d) On and after the date on which the initial performance test 

is completed or required to be completed under §60.8, whichever 

date comes first, no owner or operator of an affected facility 

that combusts oil shall cause to be discharged into the 

atmosphere from that affected facility any gases that contain SO2

in excess of 215 ng/J (0.50 lb/MMBtu) heat input from oil; or, 

as an alternative, no owner or operator of an affected facility 

that combusts oil shall combust oil in the affected facility 

that contains greater than 0.5 weight percent sulfur. The 

percent reduction requirements are not applicable to affected 

facilities under this paragraph.

(e) * * *

(1) * * *

(ii) * * *

(ii) Has a heat input capacity greater than 22 MW (75 MMBtu/h); 

and

* * * * *

(h) For affected facilities listed under paragraphs (h)(1), (2), 

(3), or (4) of this section, compliance with the emission limits 

or fuel oil sulfur limits under this section may be determined 
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based on a certification from the fuel supplier, as described 

under §60.48c(f), as applicable.

(1) * * *

(2) * * *

* * * * *

(3) Coal-fired affected facilities with heat input capacities 

between 2.9 and 8.7 MW (10 and 30 MMBtu/h).

(4) Other fuels-fired affected facilities with heat input 

capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/h).

* * * * *

33. Section 60.43c is amended as follows: 

a. By revising paragraph (a).

b. By revising paragraph (b).

c. By revising paragraph (c).

d. By revising paragraph (e).

§60.43c Standard for particulate matter (PM).

(a) On and after the date on which the initial performance test 

is completed or required to be completed under §60.8, whichever 

date comes first, no owner or operator of an affected facility 

that commenced construction, reconstruction, or modification on 

or before February 28, 2005, that combusts coal or combusts 

mixtures of coal with other fuels and has a heat input capacity 

of 8.7 MW (30 MMBtu/h) or greater, shall cause to be discharged 
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into the atmosphere from that affected facility any gases that 

contain PM in excess of the following emission limits:

* * * * *

(b) On and after the date on which the initial performance test 

is completed or required to be completed under §60.8, whichever 

date comes first, no owner or operator of an affected facility 

that commenced construction, reconstruction, or modification on 

or before February 28, 2005, that combusts wood or combusts 

mixtures of wood with other fuels (except coal) and has a heat 

input capacity of 8.7 MW (30 MMBtu/h) or greater, shall cause to 

be discharged into the atmosphere from that affected facility 

any gases that contain PM in excess of the following emissions 

limits:

* * * * *

(c) On and after the date on which the initial performance test 

is completed or required to be completed under §60.8, whichever 

date comes first, no owner or operator of an affected facility 

that combusts coal, wood, or oil and has a heat input capacity 

of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged 

into the atmosphere from that affected facility any gases that 

exhibit greater than 20 percent opacity (6-minute average), 

except for one 6-minute period per hour of not more than 27 

percent opacity. Owners and operators of an affected facility 
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that elect to install, calibrate, maintain, and operate a 

continuous emissions monitoring system (CEMS) for measuring PM 

emissions according to the requirements of this subpart and are 

subject to a federally enforceable PM limit of 0.030 lb/MMBtu or 

less are exempt from the opacity standard specified in this 

paragraph.

* * * * *

(e)(1) On and after the date on which the initial performance 

test is completed or is required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected 

facility that commences construction, reconstruction, or 

modification after February 28, 2005, and that combusts coal, 

oil, wood, a mixture of these fuels, or a mixture of these fuels 

with any other fuels and has a heat input capacity of 8.7 MW (30 

MMBtu/h) or greater shall cause to be discharged into the 

atmosphere from that affected facility any gases that contain PM 

in excess of 13 ng/J (0.030 lb/MMBtu) heat input, except as 

provided in paragraphs (e)(2), (e)(3), and (e)(4) of this 

section.

(2) * * *

(3) On and after the date on which the initial performance test 

is completed or is required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected 
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facility that commences modification after February 28, 2005, 

and that combusts over 30 percent wood (by heat input) on an 

annual basis and has a heat input capacity of 8.7 MW (30 

MMBtu/h) or greater shall cause to be discharged into the 

atmosphere from that affected facility any gases that contain PM 

in excess of 43 ng/J (0.10 lb/MMBtu) heat input.

(4) An owner or operator of an affected facility that commences 

construction, reconstruction, or modification after February 28, 

2005, and that combusts only oil that contains no more than 0.50 

weight percent sulfur or a mixture of 0.50 weight percent sulfur 

oil with other fuels not subject to a PM standard under §60.43c 

and not using a post-combustion technology (except a wet 

scrubber) to reduce PM or SO2 emissions is not subject to the PM 

limit in this section.

34. Section 60.45c is amended to read as follows:

a. By revising paragraph (c)(14).

b. By revising paragraph (d).

Section 60.45c Compliance and performance test methods and 

procedures for particulate matter.

* * * * *

(c)(14) As of January 1, 2012, and within 90 days after the date 

of completing each performance test, as defined in §60.8, 

conducted to demonstrate compliance with this subpart, you must 
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submit relative accuracy test audit (i.e., reference method) 

data and performance test (i.e., compliance test) data, except 

opacity data, electronically to EPA’s Central Data Exchange 

(CDX) by using the Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/ert tool.html/) or other 

compatible electronic spreadsheet. Only data collected using 

test methods compatible with ERT are subject to this requirement 

to be submitted electronically into EPA’s WebFIRE database.

(d) The owner or operator of an affected facility seeking to 

demonstrate compliance under §60.43c(e)(4) shall follow the 

applicable procedures under §60.48c(f). For residual oil-fired 

affected facilities, fuel supplier certifications are only 

allowed for facilities with heat input capacities between 2.9 

and 8.7 MW (10 to 30 MMBtu/h).

* * * * *

35. Section 60.47c is amended as follows:

a. By revising paragraph (a).

b. By revising paragraph (f).

c. By deleting paragraph (g).

Section 60.47c Emission monitoring for particulate matter.

(a) Except as provided in paragraphs (c), (d), (e), and (f) of 

this section, the owner or operator of an affected facility 

combusting coal, oil, or wood that is subject to the opacity 
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standards under §60.43c shall install, calibrate, maintain, and 

operate a continuous opacity monitoring system (COMS) for 

measuring the opacity of the emissions discharged to the 

atmosphere and record the output of the system. The owner or 

operator of an affected facility subject to an opacity standard 

in §60.43c(c) that is not required to use a COMS due to 

paragraphs (c), (d), (e), or (f) of this section that elects not 

to use a COMS shall conduct a performance test using Method 9 of 

appendix A–4 of this part and the procedures in §60.11 to 

demonstrate compliance with the applicable limit in §60.43c by 

April 29, 2011, within 45 days of stopping use of an existing 

COMS, or within 180 days after initial startup of the facility, 

whichever is later, and shall comply with either paragraphs 

(a)(1), (a)(2), or (a)(3) of this section. The observation 

period for Method 9 of appendix A-4 of this part performance 

tests may be reduced from 3 hours to 60 minutes if all 6-minute 

averages are less than 10 percent and all individual 15-second 

observations are less than or equal to 20 percent during the 

initial 60 minutes of observation.

(1) * * *

(i) If no visible emissions are observed, a subsequent Method 9 

of appendix A–4 of this part performance test must be completed 

within 12 calendar months from the date that the most recent 
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performance test was conducted or within 45 days of the next day 

that fuel with an opacity standard is combusted, whichever is 

later;

(ii) If visible emissions are observed but the maximum 6-minute 

average opacity is less than or equal to 5 percent, a subsequent 

Method 9 of appendix A–4 of this part performance test must be 

completed within 6 calendar months from the date that the most 

recent performance test was conducted or within 45 days of the 

next day that fuel with an opacity standard is combusted, 

whichever is later;

(iii) If the maximum 6-minute average opacity is greater than 5 

percent but less than or equal to 10 percent, a subsequent 

Method 9 of appendix A–4 of this part performance test must be 

completed within 3 calendar months from the date that the most 

recent performance test was conducted or within 45 days of the 

next day that fuel with an opacity standard is combusted, 

whichever is later; or

(iv) * * *

(2) * * *

(i) * * *

(ii) If no visible emissions are observed for 10 operating days 

during which an opacity standard is applicable, observations can 

be reduced to once every 7 operating days during which an 
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opacity standard is applicable. If any visible emissions are 

observed, daily observations shall be resumed.

* * * * *

(f) An owner or operator of an affected facility that is subject 

to an opacity standard in under §60.43c(c) is not required to 

operate a COMS provided that the affected facility meets the 

conditions in either paragraphs (f)(1), (2), or (3) of this 

section.

(1) The affected facility uses a fabric filter (baghouse) as the 

primary PM control device and, the owner or operator operates a 

bag leak detection system to monitor the performance of the 

fabric filter according to the requirements in section §60.48Da 

of this part.

(2) The affected facility uses an ESP as the primary PM control 

device, and the owner or operator uses an ESP predictive model 

to monitor the performance of the ESP developed in accordance 

and operated according to the requirements in section §60.48Da 

of this part.

(3) The affected facility burns only gaseous fuels and/or fuel 

oils that contain no greater than 0.5 weight percent sulfur, and 

the owner or operator operates the unit according to a written 

site-specific monitoring plan approved by the permitting 

authority. This monitoring plan must include procedures and 
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criteria for establishing and monitoring specific parameters for 

the affected facility indicative of compliance with the opacity

standard. For testing performed as part of this site-specific 

monitoring plan, the permitting authority may require as an 

alternative to the notification and reporting requirements 

specified in §§60.8 and 60.11 that the owner or operator submit 

any deviations with the excess emissions report required under 

§60.48c(c).

Subpart HHHH-—[Amended]

36. Subpart HHHH is removed and reserved.
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PART 63 -- [AMENDED]

37. The authority citation for 40 CFR Part 63 continues to read 

as follows:

Authority: 42 U.S.C. 7401, et seq.

Subpart A – [Amended]

38. Section 63.14 is amended as follows:

a. By revising paragraph (b)(35).

b. By revising paragraphs (b)(39) and (40).

c. By revising paragraph (b)(55).

d. By adding paragraphs (b)(69) through (72).

e. By revising paragraph (i)(1).

§63.14 Incorporation by Reference.

* * * * *

(b) * * *

(35) ASTM D6784–02 (Reapproved 2008), Standard Test Method for 

Elemental, Oxidized, Particle-Bound and Total Mercury in Flue 

Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro 

Method), approved April 1, 2008, IBR approved for table 1 to 

subpart DDDDD of this part, table 2 to subpart DDDDD of this 

part, table 5 to subpart DDDDD of this part, table 12 to subpart 

DDDDD of this part, table 4 to subpart JJJJJJ of this part, 

table 5 to subpart UUUUU of this part, and appendix A to subpart 

UUUUU of this part.
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* * * * *

(39) ASTM Method D388-05, Standard Classification of Coals by 

Rank, approved September 15, 2005, IBR approved for §63.7575,

§63.10042, and §63.11237.

(40) ASTM Method D396–10, Standard Specification for Fuel Oils, 

approved October 1, 2010, IBR approved for §63.7575 and 

§63.10042.

* * * * *

(55) ASTM D6348–03 (Reapproved 2010), Standard Test Method for 

Determination of Gaseous Compounds by Extractive Direct 

Interface Fourier Transform Infrared (FTIR) Spectroscopy,

approved October 1, 2010, IBR approved for table 1 to subpart 

UUUUU of this part, table 2 to subpart UUUUU of this part, table 

5 to subpart UUUUU of this part, and appendix B to subpart UUUUU 

of this part.

* * * * *

(69) ASTM D95-05 (Reapproved 2010), Standard Test Method for 

Water in Petroleum Products and Bituminous Materials by 

Distillation, approved May 1, 2010, IBR approved for 

§63.10005(i)(4)(A).

(70) ASTM D4006-11, Standard Test Method for Water in Crude Oil 

by Distillation, approved June 1, 2011, IBR approved for 

§63.10005(i)(4)(B).
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(71) ASTM D4057-06 (Reapproved 2011), Standard Practice for 

Manual Sampling of Petroleum and Petroleum Products, approved 

June 1, 2011, IBR approved for §63.10005(i)(4)(C).

(72) ASTM D4177-95 (Reapproved 2010), Standard Practice for 

Automatic Sampling of Petroleum and Petroleum Products, approved 

May 1, 2010, IBR approved for §63.10005(j).

* * * * *

(i) * * *

(1) ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses 

[Part 10, Instruments and Apparatus],” IBR approved for 

§§63.309(k)(1)(iii), 63.865(b), 63.3166(a)(3), 

63.3360(e)(1)(iii), 63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 

63.4362(a)(3), 63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 

63.9307(c)(2), 63.9323(a)(3), 63.11148(e)(3)(iii), 

63.11155(e)(3), 63.11162(f)(3)(iii) and (f)(4), 

63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii), 

63.11551(a)(2)(i)(C), table 5 to subpart DDDDD of this part, 

table 1 to subpart ZZZZZ of this part, table 4 to subpart 

JJJJJJ, and table 5 to subpart UUUUU of this part.

39. Part 63 is amended by adding subpart UUUUU to read as 

follows:

Subpart UUUUU -- National Emission Standards for Hazardous Air 

Pollutants: Coal- and Oil-fired Electric Utility Steam 

Generating Units
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Sec.

What This Subpart Covers

63.9980 What is the purpose of this subpart?

63.9981 Am I subject to this subpart?

63.9982 What is the affected source of this subpart?

63.9983 Are any EGUs not subject to this subpart?

63.9984 When do I have to comply with this subpart?

63.9985 What is a new EGU?

Emission Limitations and Work Practice Standards

63.9990 What are the subcategories of EGUs?

63.9991 What emission limitations, work practice standards, and 

operating limits must I meet?

General Compliance Requirements

63.10000 What are my general requirements for complying with 

this subpart?

63.10001 Affirmative Defense for Exceedence of Emission Limit 

During Malfunction.

Testing and Initial Compliance Requirements

63.10005 What are my initial compliance requirements and by what 

date must I conduct them?

63.10006 When must I conduct subsequent performance tests or 

tune-ups?

63.10007 What methods and other procedures must I use for the 

performance tests?

63.10008 [Reserved]

63.10009 May I use emissions averaging to comply with this 

subpart?

63.10010 What are my monitoring, installation, operation, and 

maintenance requirements?

63.10011 How do I demonstrate initial compliance with the 

emission limitations and work practice standards?

Continuous Compliance Requirements

63.10020 How do I monitor and collect data to demonstrate 

continuous compliance?

63.10021 How do I demonstrate continuous compliance with the 

emission limitations and work practice standards?

63.10022 How do I demonstrate continuous compliance under the 

emissions averaging provision?

63.10023 How do I establish my PM CPMS operating limit and 

determine compliance with it?
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Notifications, Reports, and Records

63.10030 What notifications must I submit and when?

63.10031 What reports must I submit and when?

63.10032 What records must I keep?

63.10033 In what form and how long must I keep my records?

Other Requirements and Information

63.10040 What parts of the General Provisions apply to me?

63.10041 Who implements and enforces this subpart?

63.10042 What definitions apply to this subpart?

Tables to Subpart UUUUU of Part 63

Table 1 to Subpart UUUUU of Part 63 - Emission Limits for New or 

Reconstructed EGUs

Table 2 to Subpart UUUUU of Part 63 – Emission Limits for 

Existing EGUs

Table 3 to Subpart UUUUU of Part 63 - Work Practice Standards

Table 4 to Subpart UUUUU of Part 63 – Operating Limits for EGUs

Table 5 to Subpart UUUUU of Part 63 - Performance Testing 

Requirements 

Table 6 to Subpart UUUUU of Part 63 – Establishing PM CPMS

Operating Limits

Table 7 to Subpart UUUUU of Part 63 – Demonstrating Continuous 

Compliance

Table 8 to Subpart UUUUU of Part 63 – Reporting Requirements

Table 9 to Subpart UUUUU of Part 63 - Applicability of General 

Provisions to Subpart UUUUU

Appendix A to Subpart UUUUU

Hg Monitoring Provisions

Appendix B to Subpart UUUUU

HCl and HF Monitoring Provisions

What This Subpart Covers

§63.9980 What is the purpose of this subpart?

This subpart establishes national emission limitations and work 
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practice standards for hazardous air pollutants (HAP) emitted 

from coal- and oil-fired electric utility steam generating units 

(EGUs) as defined in §63.10042 of this subpart. This subpart 

also establishes requirements to demonstrate initial and 

continuous compliance with the emission limitations.

§63.9981 Am I subject to this subpart?

You are subject to this subpart if you own or operate a coalfired EGU or an oil-fired EGU as defined in §63.10042 of this 

subpart.

§63.9982 What is the affected source of this subpart?

(a) This subpart applies to each individual or group of two or 

more new, reconstructed, and existing affected source(s) as 

described in paragraphs (a)(1) and (2) of this section within a 

contiguous area and under common control.

(1) The affected source of this subpart is the collection of all 

existing coal- or oil-fired EGUs, as defined in 63.10042, within 

a subcategory.

(2) The affected source of this subpart is each new or 

reconstructed coal- or oil-fired EGU as defined in 63.10042.

(b) An EGU is new if you commence construction of the coal- or 

oil-fired EGU after May 3, 2011, and you meet the applicability 

criteria at the time you commence construction.

(c) An EGU is reconstructed if you meet the reconstruction 
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criteria as defined in §63.2, you commence reconstruction after 

May 3, 2011, and you meet the applicability criteria at the time 

you commence reconstruction. 

(d) An EGU is existing if it is not new or reconstructed. An 

existing electric steam generating unit that meets the 

applicability requirements after the effective date of this 

final rule due to a change process (e.g., fuel or utilization) 

is considered to be an existing source under this subpart.

§63.9983 Are any EGUs not subject to this subpart?

The types of electric steam generating units listed in 

paragraphs (a) through (d) of this section are not subject to 

this subpart.

(a) Any unit designated as a stationary combustion turbine, 

other than an integrated gasification combined cycle (IGCC)

unit, covered by 40 CFR Part 63, subpart YYYY.

(b) Any electric utility steam generating unit that is not a 

coal- or oil-fired EGU and combusts natural gas for more than 

10.0 percent of the average annual heat input during any 3 

calendar years or for more than 15.0 percent of the annual heat 

input during any calendar year.

(c) Any electric utility steam generating unit that has the 

capability of combusting more than 25 MW of coal or oil but did 

not fire coal or oil for more than 10.0 percent of the average 
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annual heat input during any 3 calendar years or for more than 

15.0 percent of the annual heat input during any calendar year. 

Heat input means heat derived from combustion of fuel in an EGU 

and does not include the heat derived from preheated combustion 

air, recirculated flue gases or exhaust gases from other sources 

(such as stationary gas turbines, internal combustion engines, 

and industrial boilers).

(d) Any electric steam generating unit combusting solid waste is 

a solid waste incineration unit subject to standards established 

under sections 129 and 111 of the Clean Air Act.

§63.9984 When do I have to comply with this subpart?

(a) If you have a new or reconstructed EGU, you must comply with 

this subpart by [INSERT DATE 60 DAYS AFTER THIS FINAL RULE IS 

PUBLISHED IN THE FEDERAL REGISTER] or upon startup of your EGU, 

whichever is later, and as further provided for in §63.10005(g).

(b) If you have an existing EGU, you must comply with this 

subpart no later than [INSERT DATE 3 YEARS AND 60 DAYS AFTER 

THIS FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER].

(c) You must meet the notification requirements in §63.10030 

according to the schedule in §63.10030 and in subpart A of this 

part. Some of the notifications must be submitted before you are 

required to comply with the emission limits and work practice 

standards in this subpart.
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(d) An electric steam generating unit that does not meet the 

definition of an EGU subject to this subpart on [INSERT DATE 60 

DAYS AFTER THIS FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER] 

for new sources or [INSERT DATE 3 YEARS AND 60 DAYS AFTER THIS 

FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER] for existing 

sources must comply with the applicable existing source

provisions of this subpart on the date such unit meets the 

definition of an EGU subject to this subpart.

(e) If you own or operate an electric steam generating unit 

that is exempted from this subpart under §63.9983(d), if the 

manner of operating the unit changes such that the combustion of 

waste is discontinued and the unit becomes a coal-fired or oilfired EGU (as defined in §63.10042), you must be in compliance 

with this subpart on [INSERT DATE 3 YEARS AND 60 DAYS AFTER THIS 

FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER] or on the 

effective date of the switch from waste combustion to coal or 

oil combustion, whichever is later.

(f) You must demonstrate that compliance has been achieved, by 

conducting the required performance tests and other activities, 

no later than 180 days after the applicable date in paragraph 

(a), (b), (c), (d), or (e) of this section.

§63.9985 What is a new EGU?

(a) A new EGU is an EGU that meets any of the criteria specified 
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in paragraph (a)(1) through (a)(2) of this section.

(1) An EGU that commenced construction after May 3, 2011.

(2) An EGU that commenced reconstruction or modification after 

May 3, 2011.

Emission Limitations and Work Practice Standards

§63.9990 What are the subcategories of EGUs?

(a) Coal-fired EGUs are subcategorized as defined in paragraphs 

(a)(1) through (a)(2) of this section and as defined in 

§63.10042.

(1) EGUs designed for coal with a heating value greater than or 

equal to 8,300 Btu/lb, and

(2) EGUs designed for low rank virgin coal.

(b) Oil-fired EGUs are subcategorized as noted in paragraphs 

(b)(1) through (b)(4) of this section and as defined in 

§63.10042.

(1) Continental liquid oil-fired EGUs

(2) Non-continental liquid oil-fired EGUs,

(3) Limited-use liquid oil-fired EGUs, and

(4) EGUs designed to burn solid oil-derived fuel.

(c) IGCC units combusting either gasified coal or gasified solid 

oil-derived fuel. For purposes of compliance, monitoring, 

recordkeeping, and reporting requirements in this subpart, IGCC 

units are subject in the same manner as coal-fired units and 
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solid oil-derived fuel-fired units, unless otherwise indicated.

§63.9991 What emission limitations, work practice standards, and 

operating limits must I meet?

(a) You must meet the requirements in paragraphs (a)(1) and (2) 

of this section. You must meet these requirements at all times.

(1) You must meet each emission limit and work practice standard 

in Table 1 through 3 to this subpart that applies to your EGU, 

for each EGU at your source, except as provided under §63.10009.

(2) You must meet each operating limit in Table 4 to this 

subpart that applies to your EGU. 

(b) As provided in §63.6(g), the Administrator may approve use 

of an alternative to the work practice standards in this 

section.

(c) You may use the alternate SO2 limit in Tables 1 and 2 to this 

subpart only if your coal-fired EGU:

(i) Has a system using wet or dry flue gas desulfurization 

technology and SO2 continuous emissions monitoring system (CEMS)

installed on the unit; and

(ii) At all times, you operate the wet or dry flue gas 

desulfurization technology installed on the unit consistent with 

§63.10000(b).

General Compliance Requirements

§63.10000 What are my general requirements for complying with 
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this subpart?

(a) You must be in compliance with the emission limits and 

operating limits in this subpart. These limits apply to you at 

all times except during periods of startup and shutdown; 

however, for coal-fired, liquid oil-fired, or solid oil-derived

fuel-fired EGUs, you are required to meet the work practice 

requirements in Table 3 during periods of startup or shutdown.

(b) At all times you must operate and maintain any affected 

source, including associated air pollution control equipment and 

monitoring equipment, in a manner consistent with safety and 

good air pollution control practices for minimizing emissions. 

Determination of whether such operation and maintenance 

procedures are being used will be based on information available 

to the EPA Administrator which may include, but is not limited 

to, monitoring results, review of operation and maintenance 

procedures, review of operation and maintenance records, and 

inspection of the source.

(c)(1) For coal-fired units and solid oil-derived fuel-fired 

units, initial performance testing is required for all 

pollutants, to demonstrate compliance with the applicable 

emission limits. 

(i) For a coal-fired or solid oil-derived fuel-fired EGU or IGCC 

EGU, you may conduct the initial performance testing in 
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accordance with §63.10005(h), to determine whether the unit 

qualifies as a low emitting EGU (LEE) for one or more applicable 

emissions limits, with two exceptions: 

(A) You may not pursue the LEE option if your coal-fired, IGCC, 

or solid oil-derived fuel-fired EGU is equipped with an acid gas 

scrubber and has a main stack and bypass stack exhaust 

configuration, and

(B) You may not pursue the LEE option for Hg if your coal-fired, 

solid oil-fired fuel fired EGU or IGCC EGU is new. 

(ii) For a qualifying LEE for Hg emissions limits, you must 

conduct a 30-day performance test using Method 30B at least once 

every 12 calendar months to demonstrate continued LEE status. 

(iii) For a qualifying LEE of any other applicable emissions 

limits, you must conduct a performance test at least once every 

36 calendar months to demonstrate continued LEE status. 

(iv) If your coal-fired or solid oil-derived fuel-fired EGU or 

IGCC EGU does not qualify as a LEE for total non-mercury HAP 

metals, individual non-mercury HAP metals, or filterable 

particulate matter (PM), you must demonstrate compliance through 

an initial performance test and you must monitor continuous 

performance through either use of a particulate matter 

continuous parametric monitoring system (PM CPMS), a PM CEMS, or 

compliance performance testing repeated quarterly.
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(A) If you elect to use PM CPMS, you will establish a sitespecific operating limit corresponding to the results of the 

performance test demonstrating compliance with the pollutant 

with which you choose to comply: total non-mercury HAP metals, 

individual non-mercury HAP metals or filterable PM. You will use 

the PM CPMS to demonstrate continuous compliance with this 

operating limit. If you elect to use a PM CPMS, you must repeat 

the performance test annually for the selected pollutant limit 

and reassess and adjust the site-specific operating limit in 

accordance with the results of the performance test.

(B) You may also opt to install and operate a particulate matter 

CEMS certified in accordance with Performance Specification 11 

and Procedure 2 of 40 CFR part 60, Appendices B and F, 

respectively, in accordance with §63.10010(i).

(v) If your coal-fired or solid oil-derived fuel-fired EGU does 

not qualify as a LEE for hydrogen chloride (HCl), you may 

demonstrate initial and continuous compliance through use of an 

HCl CEMS, installed and operated in accordance with Appendix B 

to this subpart. As an alternative to HCl CEMS, you may 

demonstrate initial and continuous compliance by conducting an 

initial and periodic quarterly performance stack test for HCl. 

If your EGU uses wet or dry flue gas desulfurization technology 

(this includes limestone injection into a fluidized bed 
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combustion unit), you may apply a second alternative to HCl CEMS 

by installing and operating a sulfur dioxide (SO2) CEMS installed 

and operated in accordance with Part 75 of this chapter to 

demonstrate compliance with the applicable SO2 emissions limit.

(vi) If your coal-fired or solid oil-derived fuel-fired EGU does 

not qualify as a LEE for Hg, you must demonstrate initial and 

continuous compliance through use of a Hg CEMS or a sorbent trap 

monitoring system, in accordance with appendix A to this 

subpart.

(2) For liquid oil-fired EGUs, except limited use liquid oilfired EGUs, initial performance testing is required for all 

pollutants, to demonstrate compliance with the applicable 

emission limits.

(i) For an existing liquid oil-fired unit, you may conduct the 

performance testing in accordance with §63.10005(h), to 

determine whether the unit qualifies as a LEE for one or more 

pollutants. For a qualifying LEE for Hg emissions limits, you 

must conduct a 30-day performance test using Method 30B at least 

once every 12 calendar months to demonstrate continued LEE 

status. For a qualifying LEE of any other applicable emissions 

limits, you must conduct a performance test at least once every 

36 calendar months to demonstrate continued LEE status. 

(ii) If your existing liquid oil-fired unit does not qualify as 
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a LEE for total HAP metals (including mercury), individual 

metals (including mercury), or filterable PM you must 

demonstrate compliance through an initial performance test and 

you must monitor continuous performance through either use of a 

PM CPMS, a PM CEMS, or performance testing conducted quarterly.

(A) If you elect to use PM CPMS, you will establish a sitespecific operating limit corresponding to the results of the 

performance test demonstrating compliance with the pollutant 

with which you choose to comply: total HAP metals, individual 

HAP metals, or filterable PM. You will use the PM CPMS to 

demonstrate continuous compliance with this operating limit. If 

you elect to use a PM CPMS, you must repeat the performance test 

at least annually for the selected pollutant limit and reassess 

and adjust the site-specific operating limit in accordance with 

the results of the performance test.

(B) If you elect to use a PM CEMS, you will use the CEMS in 

accordance with §63.10010(i) to demonstrate initial and 

continuous compliance with the filterable PM emission limit.

(iii) If your existing liquid oil-fired unit does not qualify as 

a LEE for hydrogen chloride (HCl) or for hydrogen fluoride (HF), 

you may demonstrate initial and continuous compliance through 

use of an HCl CEMS, an HF CEMS, or an HCl and HF CEMS, installed 

and operated in accordance with Appendix B to this rule. As an 
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alternative to HCl CEMS, HF CEMS, or HCl and HF CEMS, you may 

demonstrate initial and continuous compliance by conducting

periodic quarterly performance stack tests for HCl and HF. If 

you elect to demonstrate compliance through quarterly 

performance testing, then you must also develop a site-specific 

monitoring plan to ensure that the operations of the unit remain 

consistent with those during the performance test. As another

alternative, you may measure or obtain, and keep records of, 

fuel moisture content; as long as fuel moisture does not exceed 

1.0 percent by weight, you need not conduct other HCl or HF 

monitoring or testing.

(iv) If your unit qualifies as a limited-use liquid oil-fired as 

defined in §63.10042, then you are not subject to the emission 

limits in Tables 1 and 2, but must comply with the performance 

tune-up work practice requirements in Table 3.

(d)(1) If you demonstrate compliance with any applicable 

emissions limit through use of a continuous monitoring system 

(CMS), where a CMS includes a continuous parameter monitoring 

system (CPMS) as well as a continuous emissions monitoring 

system (CEMS), you must develop a site-specific monitoring plan 

and submit this site-specific monitoring plan, if requested, at 

least 60 days before your initial performance evaluation (where 

applicable) of your CMS. This requirement also applies to you if 
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you petition the Administrator for alternative monitoring 

parameters under §63.8(f). This requirement to develop and 

submit a site-specific monitoring plan does not apply to 

affected sources with existing monitoring plans that apply to 

CEMS and CPMS prepared under Appendix B to Part 60 or Part 75 of 

this chapter, and that meet the requirements of §63.10010. Using 

the process described in §63.8(f)(4), you may request approval 

of monitoring system quality assurance and quality control 

procedures alternative to those specified in this paragraph of 

this section and, if approved, include those in your sitespecific monitoring plan. The monitoring plan must address the 

provisions in paragraphs (d)(2) through (5) of this section.

(2) The site-specific monitoring plan shall include the 

information specified in paragraphs (d)(5)(i) through 

(d)(5)(vii) of this section. Alternatively, the requirements of 

paragraphs (d)(5)(i) through (d)(5)(vii) are considered to be 

met for a particular CMS or sorbent trap monitoring system if:

(i) The CMS or sorbent trap monitoring system is installed, 

certified, maintained, operated, and quality-assured either 

according to Part 75 of this chapter, or appendix A or B to this 

subpart; and 

(ii) The recordkeeping and reporting requirements of Part 75 of 

this chapter, or appendix A or B to this subpart, that pertain 
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to the CMS are met. 

(3) If requested by the Administrator, you must submit the 

monitoring plan (or relevant portion of the plan) at least 60 

days before the initial performance evaluation of a particular 

CMS, except where the CMS has already undergone a performance 

evaluation that meets the requirements of §63.10010 (e.g., if 

the CMS was previously certified under another program). 

(4) You must operate and maintain the CMS according to the sitespecific monitoring plan.

(5) The provisions of the site-specific monitoring plan must 

address the following items:

(i) Installation of the CEMS or sorbent trap monitoring system 

sampling probe or other interface at a measurement location 

relative to each affected process unit such that the measurement 

is representative of control of the exhaust emissions (e.g., on 

or downstream of the last control device). See §63.10010(a) for 

further details. For CPMS installations, follow the procedures 

in §63.10010(h).

(ii) Performance and equipment specifications for the sample 

interface, the pollutant concentration or parametric signal 

analyzer, and the data collection and reduction systems.

(iii) Schedule for conducting initial and periodic performance 

evaluations.
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(iv) Performance evaluation procedures and acceptance criteria 

(e.g., calibrations), including ongoing data quality assurance 

procedures in accordance with the general requirements of 

§63.8(d).

(v) On-going operation and maintenance procedures, in accordance 

with the general requirements of §§63.8(c)(1)(ii), (c)(3), and 

(c)(4)(ii). 

(vi) Conditions that define a CMS that is out of control 

consistent with §63.8(c)(7)(i) and for responding to out of 

control periods consistent with §§63.8(c)(7)(ii) and (c)(8).

(vii) On-going recordkeeping and reporting procedures, in 

accordance with the general requirements of §§63.10(c), (e)(1), 

and (e)(2)(i), or as specifically required under this subpart. 

(e) As part of your demonstration of continuous compliance, you 

must perform periodic tune-ups of your EGU(s), according to 

§63.10021(e). 

(f) You are subject to the requirements of this subpart for at 

least 6 months following the last date you met the definition of 

an EGU subject to this subpart (e.g., 6 months after a 

cogeneration unit provided more than one third of its potential 

electrical output capacity and more than 25 megawatts electrical 

output to any power distributions system for sale). You may opt 

to remain subject to the provisions of this subpart beyond 6 
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months after the last date you met the definition of an EGU 

subject to this subpart, unless you are a solid waste 

incineration unit subject to standards under CAA section 129 

(e.g., 40 CFR Part 60, Subpart CCCC (New Source Performance 

Standards (NSPS) for Commercial and Industrial Solid Waste 

Incineration Units, or Subpart DDDD (Emissions Guidelines (EG) 

for Existing Commercial and Industrial Solid Waste Incineration 

Units). Notwithstanding the provisions of this subpart, an EGU 

that starts combusting solid waste is immediately subject to 

standards under CAA section 129 and the EGU remains subject to 

those standards until the EGU no longer meets the definition of 

a solid waste incineration unit consistent with the provisions 

of the applicable CAA section 129 standards.

(g) If you no longer meet the definition of an EGU subject to 

this subpart you must be in compliance with any newly applicable 

standards on the date you are no longer subject to this subpart. 

The date you are no longer subject to this subpart is a date 

selected by you, that must be at least 6 months from the date 

that you last met the definition of an EGU subject to this 

subpart or the date you begin combusting solid waste, consistent 

with §63.9983(d). Your source must remain in compliance with 

this subpart until the date you select to cease complying with 

this subpart or the date you begin combusting solid waste, 
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whichever is earlier.

(h)(1) If you own or operate an EGU that does not meet the 

definition of an EGU subject to this subpart on [INSERT DATE 3 

YEARS AND 60 DAYS AFTER DATE THE FINAL RULE IS PUBLISHED IN THE 

FEDERAL REGISTER], and you commence or recommence operations 

that cause you to meet the definition of an EGU subject to this 

subpart, you are subject to the provisions of this subpart, 

including, but not limited to, the emission limitations and the 

monitoring requirements, as of the first day you meet the 

definition of an EGU subject to this subpart. You must complete 

all initial compliance demonstrations for this subpart 

applicable to your EGU within 180 days after you commence or 

recommence operations that cause you to meet the definition of 

an EGU subject to this subpart.

(2) You must provide 30 days prior notice of the date you intend 

to commence or recommence operations that cause you to meet the 

definition of an EGU subject to this subpart. The notification 

must identify:

(i) The name of the owner or operator of the EGU, the location 

of the facility, the unit(s) that will commence or recommence 

operations that will cause the unit(s) to meet the definition of 

an EGU subject to this subpart, and the date of the notice;

(ii) The 40 CFR Part 60, Part 62, or Part 63 subpart and 
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subcategory currently applicable to your unit(s), and the 

subcategory of this subpart that will be applicable after you 

commence or recommence operation that will cause the unit(s) to 

meet the definition of an EGU subject to this subpart;

(iii) The date on which you became subject to the currently 

applicable emission limits;

(iv) The date upon which you will commence or recommence 

operations that will cause your unit to meet the definition of 

an EGU subject to this subpart, consistent with paragraph (f) of 

this section.

(i)(1) If you own or operate an EGU subject to this subpart, and 

it has been at least 6 months since you operated in a manner 

that caused you to meet the definition of an EGU subject to this 

subpart, you may, consistent with paragraph (g) of this section, 

select the date on which your EGU will no longer be subject to 

this subpart. You must be in compliance with any newly 

applicable section 112 or 129 standards on the date you 

selected.

(2) You must provide 30 days prior notice of the date your EGU 

will cease complying with this subpart. The notification must 

identify:

(i) The name of the owner or operator of the EGU(s), the 

location of the facility, the EGU(s) that will cease complying 
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with this subpart, and the date of the notice;

(ii) The currently applicable subcategory under this subpart, 

and any 40 CFR Part 60, Part 62, or Part 63 subpart and 

subcategory that will be applicable after you cease complying 

with this subpart;

(iii) The date on which you became subject to this subpart;

(iv) The date upon which you will cease complying with this 

subpart, consistent with paragraph (g) of this section.

(j) All air pollution control equipment necessary for compliance 

with any newly applicable emissions limits which apply as a 

result of the cessation or commencement or recommencement of 

operations that cause your EGU to meet the definition of an EGU 

subject to this subpart must be installed and operational as of 

the date your source ceases to be or becomes subject to this 

subpart.

(k) All monitoring systems necessary for compliance with any 

newly applicable monitoring requirements which apply as a result 

of the cessation or commencement or recommencement of operations 

that cause your EGU to meet the definition of an EGU subject to 

this subpart must be installed and operational as of the date 

your source ceases to be or becomes subject to this subpart. All 

calibration and drift checks must be performed as of the date 

your source ceases to be or becomes subject to this subpart. You 
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must also comply with provisions of §§63.10010, 63.10020, and 

63.10021 of this subpart. Relative accuracy tests must be 

performed as of the performance test deadline for PM CEMS, if 

applicable. Relative accuracy testing for other CEMS need not be 

repeated if that testing was previously performed consistent 

with CAA section 112 monitoring requirements or monitoring 

requirements under this subpart.

§63.10001 Affirmative Defense for Exceedence of Emission Limit 

During Malfunction.

In response to an action to enforce the standards set forth in 

paragraph §63.9991 you may assert an affirmative defense to a 

claim for civil penalties for exceedances of such standards that 

are caused by malfunction, as defined at 40 CFR 63.2. 

Appropriate penalties may be assessed, however, if you fail to 

meet your burden of proving all of the requirements in the 

affirmative defense. The affirmative defense shall not be 

available for claims for injunctive relief.

(a) To establish the affirmative defense in any action to 

enforce such a limit, you must timely meet the notification 

requirements in paragraph (b) of this section, and must prove by 

a preponderance of evidence that:

(1) The excess emissions: 

(i) Were caused by a sudden, infrequent, and unavoidable failure 
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of air pollution control and monitoring equipment, process 

equipment, or a process to operate in a normal or usual manner, 

and 

(ii) Could not have been prevented through careful planning, 

proper design or better operation and maintenance practices; and

(iii) Did not stem from any activity or event that could have 

been foreseen and avoided, or planned for; and

(iv) Were not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; and

(2) Repairs were made as expeditiously as possible when the 

applicable emission limitations were being exceeded. Off-shift 

and overtime labor were used, to the extent practicable to make 

these repairs; and

(3) The frequency, amount and duration of the excess emissions 

(including any bypass) were minimized to the maximum extent 

practicable during periods of such emissions; and

(4) If the excess emissions resulted from a bypass of control 

equipment or a process, then the bypass was unavoidable to 

prevent loss of life, personal injury, or severe property 

damage; and

(5) All possible steps were taken to minimize the impact of the 

excess emissions on ambient air quality, the environment and 

human health; and
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(6) All emissions monitoring and control systems were kept in 

operation if at all possible, consistent with safety and good 

air pollution control practices; and

(7) All of the actions in response to the excess emissions were 

documented by properly signed, contemporaneous operating logs; 

and

(8) At all times, the affected source was operated in a manner 

consistent with good practices for minimizing emissions; and

(9) A written root cause analysis has been prepared, the purpose 

of which is to determine, correct, and eliminate the primary 

causes of the malfunction and the excess emissions resulting 

from the malfunction event at issue. The analysis shall also 

specify, using best monitoring methods and engineering judgment, 

the amount of excess emissions that were the result of the 

malfunction.

(b) Notification. The owner or operator of the affected source 

experiencing an exceedance of its emission limit(s) during a 

malfunction shall notify the Administrator by telephone or 

facsimile (FAX) transmission as soon as possible, but no later 

than two business days after the initial occurrence of the 

malfunction or, if it is not possible to determine within two 

business days whether the malfunction caused or contributed to 

an exceedance, no later than two business days after the owner 
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or operator knew or should have known that the malfunction 

caused or contributed to an exceedance, but, in no event later 

than two business days after the end of the averaging period, if 

it wishes to avail itself of an affirmative defense to civil 

penalties for that malfunction. The owner or operator seeking to 

assert an affirmative defense shall also submit a written report 

to the Administrator within 45 days of the initial occurrence of 

the exceedance of the standard in §63.9991 to demonstrate, with 

all necessary supporting documentation, that it has met the 

requirements set forth in paragraph (a) of this section. The 

owner or operator may seek an extension of this deadline for up 

to 30 additional days by submitting a written request to the 

Administrator before the expiration of the 45 day period. Until 

a request for an extension has been approved by the 

Administrator, the owner or operator is subject to the 

requirement to submit such report within 45 days of the initial 

occurrence of the exceedance.

Testing and Initial Compliance Requirements

§63.10005 What are my initial compliance requirements and by 

what date must I conduct them?

(a) General requirements. For each of your affected EGUs, you 

must demonstrate initial compliance with each applicable 

emissions limit in Table 1 or 2 of this subpart through 
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performance testing. Where two emissions limits are specified 

for a particular pollutant (e.g., a heat input-based limit in 

lb/MMBtu and an electrical output-based limit in lb/MWh), you 

may demonstrate compliance with either emission limit. For a 

particular compliance demonstration, you may be required to 

conduct one or more of the following activities in conjunction 

with performance testing: collection of hourly electrical load 

data (megawatts); establishment of operating limits according to 

§63.10011 and Tables 4 and 7 to this subpart; and CMS 

performance evaluations. In all cases, you must demonstrate 

initial compliance no later than the applicable date in 

paragraph (f) of this section for tune-up work practices for 

existing EGUs, in §63.9984 for other requirements for existing 

EGUs, and in paragraph (g) of this section for all requirements 

for new EGUs. 

(1) To demonstrate initial compliance with an applicable 

emissions limit in Table 1 or 2 to this subpart using stack 

testing, the initial performance test generally consists of 

three runs at specified process operating conditions using 

approved methods. If you are required to establish operating 

limits (see paragraph (d) of this section and Table 4 to this 

subpart), you must collect all applicable parametric data during 

the performance test period. Also, if you choose to comply with 
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an electrical output-based emission limit, you must collect 

hourly electrical load data during the test period. 

(2) To demonstrate initial compliance using either a CMS that 

measures HAP concentrations directly (i.e., an Hg, HCl, or HF 

CEMS, or a sorbent trap monitoring system) or an SO2 or PM CEMS, 

the initial performance test consists of 30 boiler operating 

days of data collected by the initial compliance demonstration 

date specified in §63.10005 with the certified monitoring 

system.

(i) The 30-boiler operating day CMS performance test must 

demonstrate compliance with the applicable Hg, HCl, HF, PM, or 

SO2 emissions limit in Table 1 or 2 to this subpart.

(ii) If you choose to comply with an electrical output-based 

emission limit, you must collect hourly electrical load data 

during the performance test period. 

(b) Performance Testing Requirements. If you choose to use 

performance testing to demonstrate initial compliance with the 

applicable emissions limits in Tables 1 and 2 to this subpart 

for your EGUs, you must conduct the tests according to §63.10007 

and Table 5 to this subpart. For the purposes of the initial 

compliance demonstration, you may use test data and results from 

a performance test conducted prior to the date on which 

compliance is required for this rule (as specified in §63.9984), 
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provided that the following conditions are fully met:

(1) For a performance test based on stack test data, the test 

was conducted no more than 12 calendar months prior to the date 

on which compliance is required for this rule;

(2) For a performance test based on data from a certified CEMS 

or sorbent trap monitoring system, the test consists of all 

valid data CMS data recorded in the 30 boiler operating days 

immediately preceding that date;

(3) The performance test was conducted in accordance with all 

applicable requirements in §63.10007 and Table 5 to this 

subpart; 

(4) A record of all parameters needed to convert pollutant 

concentrations to units of the emission standard (e.g., stack 

flow rate, diluent gas concentrations, hourly electrical loads) 

is available for the entire performance test period; and

(5) For each performance test based on stack test data, you 

certify, and keep documentation demonstrating, that the EGU 

configuration, control devices, and fuel(s) have remained 

consistent with conditions since the prior performance test was 

conducted.

(c) Operating Limits. In accordance with §63.10010 and Table 4 

to this subpart, you may be required to establish operating 

limits using PM CPMS and using site-specific monitoring for 
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certain liquid oil-fired units as part of your initial 

compliance demonstration.

(d) CMS Requirements. If, for a particular emission or operating 

limit, you are required to (or elect to) demonstrate initial 

compliance using a continuous monitoring system, the CMS must 

pass a performance evaluation prior to the initial compliance 

demonstration. If a CMS has been previously certified under 

another state or federal program and is continuing to meet the 

on-going quality-assurance (QA) requirements of that program, 

then, provided that the certification and QA provisions of that 

program meet the applicable requirements of §§63.10010(b) 

through (h), an additional performance evaluation of the CMS is 

not required under this subpart. 

(1) For an affected coal-fired, solid oil-derived fuel-fired, or 

liquid oil-fired EGU, you may demonstrate initial compliance 

with the applicable SO2, HCl, or HF emissions limit in Table 1 or 

2 of this subpart through use of an SO2, HCl, or HF CEMS 

installed and operated in accordance with Part 75 of this 

chapter or Appendix B to this subpart, as applicable. You may 

also demonstrate compliance with a filterable PM emission limit 

in Table 1 or 2 of this subpart through use of a PM CEMS 

installed, certified, and operated in accordance with 

§63.10010(i). Initial compliance is achieved if the arithmetic 
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average of 30-boiler operating days of quality-assured CEMS 

data, expressed in units of the standard (see §63.10007(e)), 

meets the applicable SO2, PM, HCl, or HF emissions limit in Table 

1 or 2 to this subpart. Use Equation 19-19 of Method 19 in 

appendix A-7 to Part 60 of this chapter to calculate the 30-

boiler operating day average emissions rate. (Note: for this 

calculation, the term Ehj in Equation 19-19 must be in the same 

units of measure as the applicable HCl or HF emission limit in 

Table 1 or 2 to this subpart).

(2) For affected coal-fired or solid oil-derived fuel-fired EGUs 

that demonstrate compliance with the applicable emission limits 

for total non-mercury HAP metals, individual non-mercury HAP 

metals, total HAP metals, individual HAP metals, or filterable 

PM listed in Table 1 or 2 to this subpart using initial 

performance testing and continuous monitoring with PM CPMS:

(i) You must demonstrate initial compliance no later than the 

applicable date specified in §63.9984(f) for existing EGUs and 

in paragraph (g) of this section for new EGUs.

(ii) You must demonstrate continuous compliance with the PM CPMS 

site-specific operating limit that corresponding to the results 

of the performance test demonstrating compliance with the 

pollutant with which you choose to comply. 

(iii) You must repeat the performance test annually for the 
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selected pollutant emissions limit and reassess and adjust the 

site-specific operating limit in accordance with the results of 

the performance test. 

(3) For affected EGUs that are either required to or elect to 

demonstrate initial compliance with the applicable Hg emission 

limit in Table 1 or 2 of this subpart using Hg CEMS or sorbent 

trap monitoring systems, initial compliance must be demonstrated 

no later than the applicable date specified in §63.9984(f) for 

existing EGUs and in paragraph (g) of this section for new EGUs. 

Initial compliance is achieved if the arithmetic average of 30-

boiler operating days of quality-assured CEMS (or sorbent trap 

monitoring system) data, expressed in units of the standard (see 

section 6.2 of appendix A to this subpart), meets the applicable 

Hg emission limit in Table 1 or 2 to this subpart.

(4) For affected liquid oil-fired EGUs that demonstrate 

compliance with the applicable emission limits for HCl or HF 

listed in Table 1 or 2 to this subpart using quarterly testing 

and continuous monitoring with a CMS:

(i) You must demonstrate initial compliance no later than the 

applicable date specified in §63.9984 for existing EGUs and in 

paragraph (g) of this section for new EGUs.

(ii) You must demonstrate continuous compliance with the CMS 

site-specific operating limit that corresponding to the results 
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of the performance test demonstrating compliance with the HCl or 

HF emissions limit. 

(iii) You must repeat the performance test annually for the HCl 

or HF emissions limit and reassess and adjust the site-specific 

operating limit in accordance with the results of the 

performance test.

(e) Tune-ups. All affected EGUs are subject to the work practice 

standards in Table 3 of this subpart. As part of your initial 

compliance demonstration, you must conduct a performance tune-up 

of your EGU according to §63.10021(e).

(f) For existing affected sources a tune-up may occur prior to 

[INSERT DATE 60 DAYS AFTER THIS FINAL RULE IS PUBLISHED IN THE 

FEDERAL REGISTER], so that existing sources without neural 

networks have up to 42 calendar months (3 years from 

promulgation plus 180 days) or, in the case of units employing 

neural network combustion controls, up to 54 calendar months (48 

months from promulgation plus 180 days) after the date that is 

specified for your source in §63.9984 and according to the 

applicable provisions in §63.7(a)(2) as cited in Table 9 to this 

subpart to demonstrate compliance with this requirement. If a 

tune-up occurs prior to such date, the source must maintain 

adequate records to show that the tune-up met the requirements 

of this standard.
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(g) If your new or reconstructed affected source commenced 

construction or reconstruction between May 3, 2011, and July 2, 

2011, you must demonstrate initial compliance with either the 

proposed emission limits or the promulgated emission limits no 

later than 180 days after [INSERT DATE 60 DAYS AFTER PUBLICATION 

OF THIS FINAL RULE IN THE FEDERAL REGISTER] or within 180 days 

after startup of the source, whichever is later, according to 

§63.7(a)(2)(ix).

(1) For the new or reconstructed affected source described in 

this paragraph (g), if you choose to comply with the proposed 

emission limits when demonstrating initial compliance, you must 

conduct a second compliance demonstration for the promulgated 

emission limits within 3 years after [INSERT DATE 60 DAYS AFTER 

PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER] or 

within 3 years after startup of the affected source, whichever 

is later.

(2) If your new or reconstructed affected source commences 

construction or reconstruction after [INSERT DATE 60 DAYS AFTER 

PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER], you 

must demonstrate initial compliance with the promulgated 

emission limits no later than 180 days after startup of the 

source.

(h) Low emitting EGUs. The provisions of this paragraph (h) 
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apply to pollutants with emissions limits from new EGUs except 

Hg and to all pollutants with emissions limits from existing 

EGUs. You may not pursue this compliance option if your existing 

EGU is equipped with an acid gas scrubber and has a main stack 

and bypass stack exhaust configuration. 

(1) An EGU may qualify for low emitting EGU (LEE) status for Hg, 

HCl, HF, filterable PM, total non-Hg HAP metals, or individual 

non-Hg HAP metals (or total HAP metals or individual HAP metals, 

for liquid oil-fired EGUs) if you collect performance test data 

that meet the requirements of this paragraph (h), and if those 

data demonstrate:

(i) For all pollutants except Hg, performance test emissions 

results less than 50 percent of the applicable emissions limits

in Table 1 or 2 to this subpart for all required testing for 3 

consecutive years; or

(ii) For Hg emissions from an existing EGU, either: 

(A) Average emissions less than 10 percent of the applicable Hg 

emissions limit in Table 2 to this subpart (expressed either in 

units of lb/TBtu or lb/GWh); or

(B) Potential Hg mass emissions of 29.0 or fewer pounds per year 

and compliance with the applicable Hg emission limit in Table 2 

to this subpart (expressed either in units of lb/TBtu or 

lb/GWh). 
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(2) For all pollutants except Hg, you must conduct all required 

performance tests described in §63.10007 to demonstrate that a 

unit qualifies for LEE status. 

(i) When conducting emissions testing to demonstrate LEE status, 

you must increase the minimum sample volume specified in Table 1 

or 2 nominally by a factor of two.

(ii) Follow the instructions in §63.10007(e) and Table 5 to this 

subpart to convert the test data to the units of the applicable 

standard.

(3) For Hg, you must conduct a 30-boiler operating day 

performance test using Method 30B in appendix A-8 to Part 60 of 

this chapter to determine whether a unit qualifies for LEE 

status. Locate the Method 30B sampling probe tip at a point 

within the 10 percent centroidal area of the duct at a location 

that meets Method 1 in appendix A-1 to Part 60 of this chapter 

and conduct at least three nominally equal length test runs over 

the 30-boiler operating day test period. Collect Hg emissions 

data continuously over the entire test period (except when 

changing sorbent traps or performing required reference method 

QA procedures), under all process operating conditions. You may 

use a pair of sorbent traps to sample the stack gas for no more 

than 10 days. 

(i) Depending on whether you intend to assess LEE status for Hg 
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in terms of the lb/TBtu or lb/GWh emission limit in Table 2 to 

this subpart or in terms of the annual Hg mass emissions limit 

of 29.0 lb/year, you will have to collect some or all of the 

following data during the 30-boiler operating day test period 

(see paragraph (h)(3)(iii) of this section):

(A) Diluent gas (CO2 or O2) data, using either Method 3A in 

appendix A-3 to Part 60 of this chapter or a diluent gas monitor 

that has been certified according to Part 75 of this chapter. 

(B) Stack gas flow rate data, using either Method 2, 2F, or 2G 

in appendices A-1 and A-2 to Part 60 of this chapter, or a flow 

rate monitor that has been certified according to Part 75 of 

this chapter.

(C) Stack gas moisture content data, using either Method 4 in 

appendix A-1 to Part 60 of this chapter, or a moisture 

monitoring system that has been certified according to Part 75

of this chapter. Alternatively, an appropriate fuel-specific 

default moisture value from §75.11(b) of this chapter may be 

used in the calculations or you may petition the Administrator 

under §75.66 of this chapter for use of a default moisture value 

for non-coal-fired units.

(D) Hourly electrical load data (megawatts), from facility 

records.

(ii) If you use CEMS to measure CO2 (or O2) concentration, and/or 
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flow rate, and/or moisture, record hourly average values of each 

parameter throughout the 30-boiler operating day test period. If 

you opt to use EPA reference methods rather than CEMS for any 

parameter, you must perform at least one representative test run 

on each operating day of the test period, using the applicable 

reference method. 

(iii) Calculate the average Hg concentration, in μg/m3 (dry 

basis), for the 30-boiler operating day performance test, as the 

arithmetic average of all Method 30B sorbent trap results. Also 

calculate, as applicable, the average values of CO2 or O2

concentration, stack gas flow rate, stack gas moisture content, 

and electrical load for the test period. Then:

(A) To express the test results in units of lb/TBtu, follow the 

procedures in §63.10007(e). Use the average Hg concentration and 

diluent gas values in the calculations.

(B) To express the test results in units of lb/GWh, use 

Equations A-3 and A-4 in section 6.2.2 of appendix A to this 

subpart, replacing the hourly values “Ch”, “Qh”, “Bws” and “(MW)h”

with the average values of these parameters from the performance 

test.

(C) To calculate pounds of Hg per year, use one of the following 

methods:

(1) Multiply the average lb/TBtu Hg emission rate (determined 
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according to paragraph (h)(3)(iii)(A) of this section) by the 

maximum potential annual heat input to the unit (TBtu), which is 

equal to the maximum rated unit heat input (TBtu/hr) times 8,760 

hours. If the maximum rated heat input value is expressed in 

units of MMBtu/hr, multiply it by 106 to convert it to TBtu/hr; 

or

(2) Multiply the average lb/GWh Hg emission rate (determined 

according to paragraph (h)(3)(iii)(B) of this section) by the 

maximum potential annual electricity generation (GWh), which is 

equal to the maximum rated electrical output of the unit (GW) 

times 8,760 hours. If the maximum rated electrical output value 

is expressed in units of MW, multiply it by 103 to convert it to 

GW; or

(3) If an EGU has a federally-enforceable permit limit on either 

the annual heat input or the number of annual operating hours, 

you may modify the calculations in paragraph (h)(3)(iii)(C)(1) 

of this section by replacing the maximum potential annual heat 

input or 8,760 unit operating hours with the permit limit on 

annual heat input or operating hours (as applicable).

(4) For a group of affected units that vent to a common stack,

you may either assess LEE status for the units individually by 

performing a separate emission test of each unit in the duct 

leading from the unit to the common stack, or you may perform a 
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single emission test in the common stack. If you choose the 

common stack testing option, the units in the configuration 

qualify for LEE status if:

(i) The emission rate measured at the common stack is less than 

50 percent (10 percent for Hg) of the applicable emission limit 

in Table 1 or 2 to this subpart; or

(ii) For Hg from an existing EGU, the applicable Hg emission 

limit in Table 2 to this subpart is met and the potential annual 

mass emissions, calculated according to paragraph (h)(3)(iii) of 

this section (with some modifications), are less than or equal 

to 29.0 pounds times the number of units sharing the common 

stack. Base your calculations on the combined heat input 

capacity of all units sharing the stack (i.e., either the 

combined maximum rated value or, if applicable, a lower combined 

value restricted by permit conditions or operating hours). 

(5) For an affected unit with a multiple stack or duct 

configuration in which the exhaust stacks or ducts are 

downstream of all emission control devices, you must perform a 

separate emission test in each stack or duct. The unit qualifies 

for LEE status if:

(i) The emission rate, based on all test runs performed at all 

of the stacks or ducts, is less than 50 percent (10 percent for 

Hg) of the applicable emission limit in Table 1 or 2 to this 
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subpart; or

(ii) For Hg from an existing EGU, the applicable Hg emission 

limit in Table 2 to this subpart is met and the potential annual 

mass emissions, calculated according to paragraph (h)(3)(iii) of 

this section, are less than or equal to 29.0 pounds. Use the 

average Hg emission rate from paragraph (h)(5)(i) of this 

section in your calculations.

(i) Liquid-oil fuel moisture measurement. If your EGU combusts 

liquid fuels, if your fuel moisture content is no greater than 

1.0 percent by weight, and if you would like to demonstrate 

initial and ongoing compliance with HCl and HF emissions limits, 

you must meet the requirements of paragraph (i)(1)-(5) of this 

section.

(1) Measure fuel moisture content of each shipment of fuel 

if your fuel arrives on a batch basis; or

(2) Measure fuel moisture content daily if your fuel 

arrives on a continuous basis; or

(3) Obtain and maintain a fuel moisture certification from 

your fuel supplier. 

(4) Use one of the following methods to determine fuel 

moisture content:
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Page 899 of 1103

(A) ASTM D95-05 (Reapproved 2010), “Standard Test Method 

for Water in Petroleum Products and Bituminous Materials by 

Distillation,” or

(B) ASTM D4006-11, “Standard Test Method for Water in Crude 

Oil by Distillation,” or

(C) ASTM D4177-95 (Reapproved 2010), “Standard Practice for 

Automatic Sampling of Petroleum and Petroleum Products,” or

(D) ASTM D4057-06 (Reapproved 2011) “Standard Practice for 

Manual Sampling of Petroleum and Petroleum Products.”

(5) Should the moisture in your liquid fuel be more than 

1.0 percent by weight, you must 

(A) Conduct HCl and HF emissions testing quarterly (and 

monitor site-specific operating parameters as provided in 

§63.10000(c)(2)(iii) or

(B) Use an HCl CEMS and/or HF CEMS.

(j) Startup and shutdown for coal-fired or solid oil derivedfired units. You must follow the requirements given in Table 3.

(k) You must submit a Notification of Compliance Status 

summarizing the results of your initial compliance 

demonstration, as provided in §63.10030.

§63.10006 When must I conduct subsequent performance tests or 

tune-ups?

(a) For liquid oil-fired, solid oil-derived fuel- and coal-fired 
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EGUs and IGCC units using PM CPMS to monitor continuous 

performance with an applicable emission limit as provided for 

under §63.10000(c), you must conduct all applicable performance 

tests according to Table 5 and §63.10007 at least every year.

(b) For affected units meeting the LEE requirements of 

§63.10005(h), you must repeat the performance test once every 3 

years (once every year for Hg) according to Table 5 and 

§63.10007. Should subsequent emissions testing results show the 

unit does not meet the LEE eligibility requirements, LEE status 

is lost. If this should occur:

(1) For all pollutant emission limits except for Hg, you must

conduct emissions testing quarterly, except as otherwise 

provided in §63.10021(d)(1).

(2) For Hg, you must install, certify, maintain, and operate a 

Hg CEMS or a sorbent trap monitoring system in accordance with 

appendix A to this subpart, within 6 calendar months of losing 

LEE eligibility. Until the Hg CEMS or sorbent trap monitoring 

system is installed, certified, and operating, you must conduct 

Hg emissions testing quarterly, except as otherwise provided in 

§63.10021(d)(1). You must have 3 calendar years of testing and 

CEMS or sorbent trap monitoring system data that satisfy the LEE 

emissions criteria to reestablish LEE status.

(c) Except where paragraphs (a) or (b) apply, or where you 
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install, certify, and operate a PM CEMS to demonstrate 

compliance with a filterable PM emission limit, for liquid oilfired EGUs, you must conduct all applicable periodic emissions

tests for filterable PM, or individual or total HAP metals 

emissions according to Table 5 and §63.10007 at least quarterly, 

except as otherwise provided in §63.10021(d)(1).

(d) Except where paragraph (b) applies, for solid oil-derived 

fuel- and coal-fired EGUs that do not use either an HCl CEMSto 

monitor compliance with the HCl limit or an SO2 CEMS to monitor

compliance with the alternate equivalent SO2 emission limit, you 

must conduct all applicable periodic HCl emissions tests 

according to Table 5 and §63.10007 at least quarterly, except as 

otherwise provided in §63.10021(d)(1).

(e) Except where paragraph (b) applies, for liquid oil-fired 

EGUs without HCl CEMS, HF CEMS, or HCl and HF CEMS, you must 

conduct all applicable emissions tests for HCl, HF, or HCl and 

HF emissions according to Table 5 and §63.10007 at least 

quarterly, except as otherwise provided in §63.10021(d)(1), and 

conduct site-specific monitoring under a plan as provided for in 

§63.10000(c)(2)(iii).

(f) Unless you follow the requirements listed in paragraphs (g) 

and (h) of this section, performance tests required at least 

every 3 calendar years must be completed within 35 to 37 
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calendar months after the previous performance test; performance 

tests required at least every year must be completed within 11 

to 13 calendar months after the previous performance test; and 

performance tests required at least quarterly must be completed 

within 80 to 100 calendar days after the previous performance 

test, except as otherwise provided in §63.10021(d)(1).

(g) If you elect to demonstrate compliance using emissions

averaging under §63.10009, you must continue to conduct 

performance stack tests at the appropriate frequency given in 

section (c) through (f) of this section.

(h) If a performance test on a non-mercury LEE shows emissions 

in excess of 50 percent of the emission limit and if you choose 

to reapply for LEE status, you must conduct performance tests at 

the appropriate frequency given in section (c) through (e) of 

this section for that pollutant until all performance tests over 

a consecutive 3-year period show compliance with the LEE 

criteria.

(i) If you are required to meet an applicable tune-up work 

practice standard, you must conduct a performance tune-up 

according to §63.10021(e). 

(1) For EGUs not employing neural network combustion 

optimization during normal operation, each performance tune-up 

specified in §63.10021(e) must be no more than 36 calendar 
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months after the previous performance tune-up.

(2) For EGUs employing neural network combustion optimization 

systems during normal operation, each performance tune-up 

specified in §63.10021(e) must be no more than 48 calendar 

months after the previous performance tune-up. 

(j) You must report the results of performance tests and 

performance tune-ups within 60 days after the completion of the 

performance tests and performance tune-ups. The reports for all 

subsequent performance tests must include all applicable 

information required in §63.10031.

§63.10007 What methods and other procedures must I use for the 

performance tests?

(a) Except as otherwise provided in this section, you must 

conduct all required performance tests according to §63.7(d), 

(e), (f), and (h). You must also develop a site-specific test 

plan according to the requirements in §63.7(c).

1) If you use CEMS (Hg, HCl, SO2, or other) to determine 

compliance with a 30-boiler operating day rolling average 

emission limit, you must collect data for all nonexempt unit 

operating conditions (see §63.10011(g) and Table 3).

(2) If you conduct performance testing with test methods in lieu 

of continuous monitoring, operate the unit at maximum normal 

operating load conditions during each periodic (e.g., quarterly) 
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performance test. Maximum normal operating load will be 

generally between 90 and 110 percent of design capacity but 

should be representative of site specific normal operations 

during each test run.

(3) For establishing operating limits with particulate matter 

continuous parametric monitoring system (PM CPMS) to demonstrate 

compliance with a PM or non Hg metals emissions limit, operate 

the unit at maximum normal operating load conditions during the 

performance test period. Maximum normal operating load will be 

generally between 90 and 110 percent of design capacity but 

should be representative of site specific normal operations 

during each test run.

(b) You must conduct each performance test (including 

traditional 3-run stack tests, 30-boiler operating day tests 

based on CEMS data (or sorbent trap monitoring system data), and 

30-boiler operating day Hg emission tests for LEE qualification) 

according to the requirements in Table 5 to this subpart.

(c) If you choose to comply with the filterable PM emission 

limit and demonstrate continuous performance using a PM CPMS for 

an applicable emission limit as provided for in §63.10000(c), 

you must also establish an operating limit according to 

§63.10011(b)(5) and Tables 4 and 6 to this subpart. Should you 

desire to have operating limits that correspond to loads other 
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than maximum normal operating load, you must conduct testing at 

those other loads to determine the additional operating limits. 

(d) Except for a 30 boiler operating day performance test based 

on CEMS (or sorbent trap monitoring system) data, where the 

concept of test runs does not apply, you must conduct a minimum 

of three separate test runs for each performance test, as 

specified in §63.7(e)(3). Each test run must comply with the 

minimum applicable sampling time or volume specified in Table 1 

or 2 to this subpart. Sections 63.10005(d) and (h),

respectively, provide special instructions for conducting 

performance tests based on CEMS or sorbent trap monitoring 

systems, and for conducting emission tests for LEE 

qualification. 

(e) To use the results of performance testing to determine 

compliance with the applicable emission limits in Table 1 or 2 

to this subpart, proceed as follows:

(1) Except for a 30-boiler operating day performance test based 

on CEMS (or sorbent trap monitoring system) data, if measurement 

results for any pollutant are reported as below the method 

detection level (e.g., laboratory analytical results for one or 

more sample components are below the method defined analytical 

detection level), you must use the method detection level as the 

measured emissions level for that pollutant in calculating 
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Page 906 of 1103

compliance. The measured result for a multiple component 

analysis (e.g., analytical values for multiple Method 29 

fractions both for individual HAP metals and for total HAP 

metals) may include a combination of method detection level data 

and analytical data reported above the method detection level.

(2) If the limits are expressed in lb/MMBtu or lb/TBtu, you must 

use the F-factor methodology and equations in sections 12.2 and 

12.3 of EPA Method 19 in appendix A-7 to Part 60 of this 

chapter. In cases where an appropriate F-factor is not listed in 

Table 19-2 of Method 19, you may use F-factors from Table 1 in 

section 3.3.5 of appendix F to Part 75 of this chapter, or Ffactors derived using the procedures in section 3.3.6 of 

appendix to Part 75 of this chapter. Use the following factors 

to convert the pollutant concentrations measured during the 

initial performance tests to units of lb/scf, for use in the 

applicable Method 19 equations:

(i) Multiply SO2 ppm by 1.66 x 10-7;

(ii) Multiply HCl ppm by 9.43 x 10-8;

(iii) Multiply HF ppm by 5.18 x 10-8;

(iv) Multiply HAP metals concentrations (mg/dscm) by 6.24 x 10-8; 

and

(v) Multiply Hg concentrations (μg/scm) by 6.24 x 10-11.

(3) To determine compliance with emission limits expressed in 
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lb/MWh or lb/GWh, you must first calculate the pollutant mass 

emission rate during the performance test, in units of lb/h. For 

Hg, if a CEMS or sorbent trap monitoring system is used, use 

Equation A-2 or A-3 in appendix A to this subpart (as 

applicable). In all other cases, use an equation that has the 

general form of Equation A-2 or A-3, replacing the value of K 

with 1.66 x 10-7 lb/scf-ppm for SO2, 9.43 x 10-8 lb/scf-ppm for 

HCl (if an HCl CEMS is used), 5.18 x 10-8 lb/scf-ppm for HF (if 

an HF CEMS is used), or 6.24 x 10-8 lb-scm/mg-scf for HAP metals 

and for HCl and HF (when performance stack testing is used), and 

defining Ch as the average SO2, HCl, or HF concentration in ppm, 

or the average HAP metals concentration in mg/dscm. This 

calculation requires stack gas volumetric flow rate (scfh) and 

(in some cases) moisture content data (see §§63.10005(h)(3) and 

63.10010). Then, if the applicable emission limit is in units of 

lb/GWh, use Equation A-4 in appendix A to this subpart to 

calculate the pollutant emission rate in lb/GWh. In this 

calculation, define (M)h as the calculated pollutant mass 

emission rate for the performance test (lb/h), and define (MW)h

as the average electrical load during the performance test 

(megawatts). If the applicable emission limit is in lb/MWh 

rather than lb/GWh, omit the 103 term from Equation A-4 to 

determine the pollutant emission rate in lb/MWh.
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Page 908 of 1103

(f) Upon request, you shall make available to the EPA 

Administrator such records as may be necessary to determine 

whether the performance tests have been done according to the 

requirements of this section.

§63.10008 [Reserved]

§63.10009 May I use emissions averaging to comply with this 

subpart?

(a) General eligibility. (1) You may use emissions averaging as 

described in paragraph (2) below as an alternative to meeting 

the requirements of §63.9991 for filterable PM, SO2, HF, HCl, 

non-Hg HAP metals, or Hg on an EGU-specific basis if:

(i) You have more than one existing EGU in the same subcategory 

located at one or more contiguous properties, belonging to a 

single major industrial grouping, which are under common control 

of the same person (or persons under common control); and 

(ii) You use CEMS (or sorbent trap monitoring systems for 

determining Hg emissions) or quarterly emissions testing for 

demonstrating compliance.

(2) You may demonstrate compliance by emissions averaging among 

the existing EGUs in the same subcategory, if your averaged Hg 

emissions for EGUs in the “unit designed for coal > 8,300 

Btu/lb” subcategory are equal to or less than 1.0 lb/TBtu or 

1.1E-2 lb/GWh or if your averaged emissions of individual, other 
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Page 909 of 1103

pollutants from other subcategories of such EGUs are equal to or 

less than the applicable emissions limit in Table 2, according 

to the procedures in this section. Note that except for Hg 

emissions from EGUs in the “unit designed for coal > 8,300 

Btu/lb” subcategory, the averaging time for emissions averaging 

for pollutants is 30 days (rolling daily) using data from CEMS 

or a combination of data from CEMS and manual performance 

testing. The averaging time for emissions averaging for Hg from 

EGUs in the “unit designed for coal > 8,300 Btu/lb” subcategory

is 90 days (rolling daily) using data from CEMS, sorbent trap 

monitoring, or a combination of monitoring data and data from 

manual performance testing. For the purposes of this paragraph, 

30 (or 90 day) group boiler operating days is defined as a 

period during which at least one unit in the emissions averaging 

group has operated 30 (or 90) days. You must calculate the 

weighted average emissions rate for the group in accordance with 

the procedures in this paragraph using the data from all units 

in the group including any that operate fewer than 30 (or 90) 

days during the preceding 30 (or 90) group boiler days.

(i) You may choose to have your EGU emissions averaging group 

meet either the heat input basis (MMBtu or TBtu, as appropriate 

for the pollutant) or gross electrical output basis (MWh or GWh, 

as appropriate for the pollutant). 
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(ii) You may not mix bases within your EGU emissions averaging 

group. 

(iii) You may use emissions averaging for affected units in 

different subcategories if the units vent to the atmosphere 

through a common stack (see paragraph (m) of this section).

(b) Equations. Use the following equations when performing 

calculations for your EGU emissions averaging group:

(1) Group eligibility equations.

 =

∑ [∑ ( × 

)





]





 + ∑ ( × 

)





∑ [∑ 





]





 + ∑ 





(. 1)

Where:

WAERm = Weighted average emissions rate maximum in terms of 

lb/heat input or lb/gross electrical output,

Hermi = Hourly emissions rate (e.g., lb/MMBtu, lb/MWh) from CEMS 

or sorbent trap monitoring for hour i, 

Rmmi = Maximum rated heat input or gross electrical output of 

unit i in terms of heat input or gross electrical output,

p = number of EGUs in emissions averaging group that rely on 

CEMS,

n = number of hourly rates collected over 30 group boiler 

operating days,

Teri = Emissions rate from most recent test of unit i in terms of 

lb/heat input or lb/gross electrical output,

Rmti = Maximum rated heat input or gross electrical output of 

unit i in terms of lb/heat input or lb/gross electrical output, 

and

m = number of EGUs in emissions averaging group that rely on 

emissions testing.

 =

∑ [∑ ( ×  × 

)





]





 + ∑ ( ×  × 

)





∑ [∑ 



 × 

]





 + ∑  × 





(. 1)

Where:

variables with similar names share the descriptions for Equation 
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Page 911 of 1103

1a,

Smmi = maximum steam generation in units of pounds from unit i 

that uses CEMS or sorbent trap monitoring, 

Cfmi = conversion factor, calculated from the most recent 

emissions test results, in units of heat input per pound of 

steam generated or gross electrical output per pound of steam 

generated, from unit i that uses CEMS or sorbent trap 

monitoring,

Smti = maximum steam generation in units of pounds from unit i 

that uses emissions testing, and 

Cfti = conversion factor, calculated from the most recent 

emissions test results, in units of heat input per pound of 

steam generated or gross electrical output per pound of steam 

generated, from unit i that uses emissions testing.

(2) Weighted 30 day rolling average emissions rate equations for 

pollutants other than Hg. Use equation 2a or 2b to calculate the 

30 day rolling average emissions daily.

 =

∑ [∑ ( × )





]



 + ∑ ( × 

)





∑ ∑ ()











 + ∑ 





(. 2)

Where:

Heri = hourly emission rate (e.g., lb/MMBtu, lb/MWh) from unit 

i’s CEMS for the preceding 30 group boiler operating days,

Rmi = hourly heat input or gross electrical output from unit i 

for the preceding 30 group boiler operating days,

p = number of EGUs in emissions averaging group that rely on 

CEMS or sorbent trap monitoring,

n = number of hourly rates collected over 30 group boiler 

operating days,

Teri = Emissions rate from most recent emissions test of unit i 

in terms of lb/heat input or lb/gross electrical output,

Rti = Maximum rated heat input or gross electrical output of unit 

i in terms of lb/heat input or lb/gross electrical output, and

m = number of EGUs in emissions averaging group that rely on 

emissions testing.
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Page 912 of 1103

 =

∑ [∑ ( ×  × )





]



 + ∑ ( ×  × 

)





∑ [∑ ( × )





]



 + ∑  × 





(. 2)

Where:

variables with similar names share the descriptions for Equation 

2a,

Smi = steam generation in units of pounds from unit i that uses 

CEMS for the preceding 30 group boiler operating days, 

Cfmi = conversion factor, calculated from the most recent 

compliance test results, in units of heat input per pound of 

steam generated or gross electrical output per pound of steam 

generated, from unit i that uses CEMS from the preceding 30 

group boiler operating days,

Sti = steam generation in units of pounds from unit i that uses 

emissions testing, and 

Cfti = conversion factor, calculated from the most recent 

compliance test results, in units of heat input per pound of 

steam generated or gross electrical output per pound of steam 

generated, from unit i that uses emissions testing.

(3) Weighted 90-boiler operating day rolling average emissions 

rate equations for Hg emissions from EGUs in the “unit designed 

for coal > 8,300 Btu/lb” subcategory. Use equation 3a or 3b to 

calculate the 90 day rolling average emissions daily.

 =

∑ [∑ ( × )





]



 + ∑ ( × 

)





∑ ∑ ()











 + ∑ 





(. 3)

Where:

Heri = hourly emission rate from unit i’s CEMS or Hg sorbent trap 

monitoring for the preceding 90 group boiler operating days,

Rmi = hourly heat input or gross electrical output from unit i 

for the preceding 90 group boiler operating days,

p = number of EGUs in emissions averaging group that rely on 

CEMS,

n = number of hourly rates collected over the 90 group boiler 
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Page 913 of 1103

operating days,

Teri = Emissions rate from most recent emissions test of unit i 

in terms of lb/heat input or lb/gross electrical output,

Rti = Maximum rated heat input or gross electrical output of unit 

i in terms of lb/heat input or lb/gross electrical output, and

m = number of EGUs in emissions averaging group that rely on 

emissions testing.

 =

∑ [∑ ( ×  × )





]



 + ∑ ( ×  × 

)





∑ [∑ ( × )





]



 + ∑  × 





(. 3)

Where:

variables with similar names share the descriptions for Equation 

2a,

Smi = steam generation in units of pounds from unit i that uses 

CEMS or a Hg sorbent trap monitoring for the preceding 90 group 

boiler operating days, 

Cfmi = conversion factor, calculated from the most recent 

compliance test results, in units of heat input per pound of 

steam generated or gross electrical output per pound of steam 

generated, from unit i that uses CEMS or sorbent trap monitoring 

from the preceding 90 group boiler operating days,

Sti = steam generation in units of pounds from unit i that uses

emissions testing, and 

Cfti = conversion factor, calculated from the most recent 

emissions test results, in units of heat input per pound of 

steam generated or gross electrical output per pound of steam 

generated, from unit i that uses emissions testing.

(c) Separate stack requirements. For a group of two or more 

existing EGUs in the same subcategory that each vent to a 

separate stack, you may average filterable PM, SO2, HF, HCl, nonHg HAP metals, or Hg emissions to demonstrate compliance with 

the limits in Table 2 to this subpart if you satisfy the 

requirements in paragraphs (d) through (j) of this section.

(d) For each existing EGU in the averaging group:

(1) The emissions rate achieved during the initial performance
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test for the HAP being averaged must not exceed the emissions

level that was being achieved 180 days after [INSERT DATE 3 

YEARS AND 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE 

FEDERAL REGISTER], or the date on which emissions testing done 

to support your emissions averaging plan is complete (if the 

Administrator does not require submission and approval of your 

emissions averaging plan), or the date that you begin emissions 

averaging, whichever is earlier; or 

(2) The control technology employed during the initial 

performance test must not be less than the design efficiency of 

the emissions control technology employed 180 days after [INSERT 

DATE 3 YEARS AND 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN 

THE FEDERAL REGISTER] or the date that you begin emissions 

averaging, whichever is earlier.

(e) The weighted-average emissions rate from the existing EGUs 

participating in the emissions averaging option must be in 

compliance with the limits in Table 2 to this subpart at all 

times following the compliance date specified 180 days after 

[INSERT DATE 3 YEARS AND 60 DAYS AFTER PUBLICATION OF THIS FINAL 

RULE IN THE FEDERAL REGISTER], or the date on which you complete 

the emissions measurements used to support your emissions 

averaging plan (if the Administrator does not require submission 

and approval of your emissions averaging plan), or the date that 
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you begin emissions averaging, whichever is earlier.

(f) Emissions averaging group eligibility demonstration. You 

must demonstrate the ability for the EGUs included in the 

emissions averaging group to demonstrate initial compliance 

according to paragraph (e)(1) or (2) of this section using the 

maximum normal operating load of each EGU and the results of the 

initial performance tests. For this demonstration and prior to 

submitting your emissions averaging plan, if requested, you must 

conduct required emissions monitoring for 30 days of boiler 

operation and any required manual performance testing to 

calculate an initial weighted average emissions rate in

accordance with this section. Should the Administrator require 

approval, you must submit your proposed emissions averaging plan 

and supporting data at least 120 days before [INSERT DATE 3 

YEARS AND 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE 

FEDERAL REGISTER]. If the Administrator requires approval of 

your plan, you may not begin using emissions averaging until the 

Administrator approves your plan.

(1) You must use Equation 1a in paragraph (b) of this section to 

demonstrate that the maximum weighted average emissions rates of 

filterable PM, HF, SO2, HCl, non-Hg HAP metals, or Hg emissions

from the existing units participating in the emissions averaging 

option do not exceed the emissions limits in Table 2 to this 
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subpart.

(2) If you are not capable of monitoring heat input or gross 

electrical output, and the EGU generates steam for purposes 

other than generating electricity, you may use Equation 1b of 

this section as an alternative to using Equation 1a of this 

section to demonstrate that the maximum weighted average 

emissions rates of filterable PM, HF, SO2, HCl, non-Hg HAP 

metals, or Hg emissions from the existing units participating in 

the emissions averaging group do not exceed the emission limits 

in Table 2 to this subpart.

(g) You must determine the weighted average emissions rate in 

units of the applicable emissions limit on a 30 day rolling 

average (90 day rolling average for Hg) basis according to 

paragraphs (f)(1) through (3) of this section. The first 

averaging period begins on 30 (or 90 for Hg) days after [INSERT 

DATE 3 YEARS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL 

REGISTER] or the date that you begin emissions averaging, 

whichever is earlier.

(1) You must use Equation 2a or 3a of paragraph (b) of this 

section to calculate the weighted average emissions rate using 

the actual heat input or gross electrical output for each 

existing unit participating in the emissions averaging option.

(2) If you are not capable of monitoring heat input or gross 
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electrical output, you may use Equation 2b or 3b of paragraph 

(b) of this section as an alternative to using Equation 2a of 

paragraph (b) of this section to calculate the average weighted 

emission rate using the actual steam generation from the units 

participating in the emissions averaging option.

(h) CEMS (or sorbent trap monitoring) use. If an EGU in your 

emissions averaging group uses CEMS (or a sorbent trap monitor 

for Hg emissions) to demonstrate compliance, you must use those 

data to determine the 30 (or 90) group boiler operating day 

rolling average emissions rate. (i) Emissions testing. If you 

use manual emissions testing to demonstrate compliance for one 

or more EGUs in your emissions averaging group, you must use the 

results from the most recent performance test to determine the 

30 (or 90) day rolling average. You may use CEMS or sorbent trap 

data in combination with data from the most recent manual 

performance test in calculating the 30 (or 90) group boiler 

operating day rolling average emissions rate.

(j) Emissions averaging plan. You must develop an implementation 

plan for emissions averaging according to the following 

procedures and requirements in paragraphs (j)(1) and (2) of this 

section.

(1) You must include the information contained in paragraphs 

(j)(1)(i) through (v) of this section in your implementation 
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plan for all the emissions units included in an emissions 

averaging:

(i) The identification of all existing EGUs in the emissions 

averaging group, including for each either the applicable HAP 

emission level or the control technology installed as of 180 

days after [INSERT DATE 3 YEARS AFTER PUBLICATION OF THIS FINAL 

RULE IN THE FEDERAL REGISTER], or the date on which you complete 

the emissions measurements used to support your emissions 

averaging plan (if the Administrator does not require submission 

and approval of your emissions averaging plan), or the date that 

you begin emissions averaging, whichever is earlier; and the 

date on which you are requesting emissions averaging to 

commence;

(ii) The process weighting parameter (heat input, gross 

electrical output, or steam generated) that will be monitored 

for each averaging group;

(iii) The specific control technology or pollution prevention 

measure to be used for each emission EGU in the averaging group 

and the date of its installation or application. If the 

pollution prevention measure reduces or eliminates emissions 

from multiple EGUs, you must identify each EGU;

(iv) The means of measurement (e.g., CEMS, sorbent trap 

monitoring, manual performance test) of filterable PM, SO2, HF, 
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HCl, individual or total non-Hg HAP metals, or Hg emissions in 

accordance with the requirements in §63.10007 and to be used in 

the emissions averaging calculations; and

(v) A demonstration that emissions averaging can produce 

compliance with each of the applicable emission limit(s) in 

accordance with (b)(1) of this paragraph.

(2) If the Administrator requests you to submit the plan for 

review and approval, you must submit a complete implementation 

plan at least 120 days before [INSERT DATE 3 YEARS AND 60 DAYS 

AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER]. 

If the Administrator requests you to submit the plan for review 

and approval, you must receive approval before initiating 

emissions averaging.

(i) The Administrator shall use following criteria in reviewing

and approving or disapproving the plan:

(A) Whether the content of the plan includes all of the 

information specified in paragraph (h)(1) of this section; and

(B) Whether the plan presents information sufficient to 

determine that compliance will be achieved and maintained.

(ii) The Administrator shall not approve an emissions averaging 

implementation plan containing any of the following provisions:

(A) Any averaging between emissions of different pollutants or 

between units located at different facilities; or
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(B) The inclusion of any emissions unit other than an existing 

unit in the same subcategory.

(k) Common stack requirements. For a group of two or more 

existing affected units, each of which vents through a single 

common stack, you may average emissions to demonstrate 

compliance with the limits in Table 2 to this subpart if you 

satisfy the requirements in paragraph (l) or (m) of this 

section.

(l) For a group of two or more existing units in the same 

subcategory and which vent through a common emissions control 

system to a common stack that does not receive emissions from 

units in other subcategories or categories, you may treat such 

averaging group as a single existing unit for purposes of this 

subpart and comply with the requirements of this subpart as if 

the group were a single unit.

(m) For all other groups of units subject to paragraph (k) of 

this section, you may elect to conduct manual performance tests 

according to procedures specified in §63.10007 in the common 

stack. If emissions from affected units included in the 

emissions averaging and from other units not included in the 

emissions averaging (e.g., in a different subcategory) or other 

nonaffected units all vent to the common stack, you must shut 

down the units not included in the emissions averaging and the 
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nonaffected units or vent their emissions to a different stack 

during the performance test. Alternatively, you may conduct a 

performance test of the combined emissions in the common stack 

with all units operating and show that show that the combined 

emissions meet the most stringent emissions limit. You may also 

use a CEMS or sorbent trap monitoring to apply this latter 

alternative to demonstrate that the combined emissions comply 

with the most stringent emissions limit on a continuous basis. 

(n) Combination requirements. The common stack of a group of two 

or more existing EGUs in the same subcategory subject to 

paragraph (k) of this section may be treated as a single stack 

for purposes of paragraph (c) of this section and included in an 

emissions averaging group subject to paragraph (c) of this 

section.

§63.10010 What are my monitoring, installation, operation, and 

maintenance requirements?

(a) Flue gases from the affected units under this subpart 

exhaust to the atmosphere through a variety of different 

configurations, including but not limited to individual stacks, 

a common stack configuration or a main stack plus a bypass 

stack. For the CEMS, PM CPMS, and sorbent trap monitoring 

systems used to provide data under this subpart, the continuous 

monitoring system installation requirements for these exhaust 
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configurations are as follows:

(1) Single Unit-Single Stack Configurations. For an affected 

unit that exhausts to the atmosphere through a single, dedicated 

stack, you shall either install the required CEMS, PM CPMS, and 

sorbent trap monitoring systems in the stack or at a location in 

the ductwork downstream of all emissions control devices, where 

the pollutant and diluents concentrations are representative of 

the emissions that exit to the atmosphere.

(2) Unit Utilizing Common Stack with Other Affected Unit(s).

When an affected unit utilizes a common stack with one or more 

other affected units, but no non-affected units, you shall 

either:

(i) Install the required CEMS, PM CPMS, and sorbent trap 

monitoring systems in the duct leading to the common stack from 

each unit; or

(ii) Install the required CEMS, PM CPMS, and sorbent trap 

monitoring systems in the common stack. 

(3) Unit(s) Utilizing Common Stack with Non-affected Unit(s). 

(i) When one or more affected units shares a common stack with 

one or more non-affected units, you shall either:

(A) Install the required CEMS, PM CPMS, and sorbent trap 

monitoring systems in the ducts leading to the common stack from 

each affected unit; or
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(B) Install the required CEMS, PM CPMS, and sorbent trap 

monitoring systems described in this section in the common stack 

and attribute all of the emissions measured at the common stack 

to the affected unit(s).

(ii) If you choose the common stack monitoring option:

(A) For each hour in which valid data are obtained for all 

parameters, you must calculate the pollutant emission rate and

(B) You must assign the calculated pollutant emission rate to 

each unit that shares the common stack. 

(4) Unit with a Main Stack and a Bypass Stack. If the exhaust 

configuration of an affected unit consists of a main stack and a 

bypass stack, you shall install CEMS on both the main stack and 

the bypass stack, or, if it is not feasible to certify and 

quality-assure the data from a monitoring system on the bypass 

stack, you shall install a CEMS only on the main stack and count 

bypass hours of deviation from the monitoring requirements. 

(5) Unit with a Common Control Device with Multiple Stack or 

Duct Configuration. If the flue gases from an affected unit,

which is configured such that emissions are controlled with a 

common control device or series of control devices, are 

discharged to the atmosphere through more than one stack or are 

fed into a single stack through two or more ducts, you may:

(i) Install required CEMS, PM CPMS, and sorbent trap monitoring 
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systems in each of the multiple stacks;

(ii) Install required CEMS, PM CPMS, and sorbent trap monitoring 

systems in each of the ducts that feed into the stack; 

(iii) Install required CEMS, PM CPMS, and sorbent trap 

monitoring systems in one of the multiple stacks or ducts and 

monitor the flows and dilution rates in all multiple stacks or 

ducts in order to determine total exhaust gas flow rate and 

pollutant mass emissions rate in accordance with the applicable 

limit; or 

(iv) In the case of multiple ducts feeding into a single stack, 

install CEMS, PM CPMS, and sorbent trap monitoring systems in 

the single stack as described in paragraph (a)(1) of this 

section.

(6) Unit with Multiple Parallel Control Devices with Multiple 

Stacks. If the flue gases from an affected unit, which is 

configured such that emissions are controlled with multiple 

parallel control devices or multiple series of control devices 

are discharged to the atmosphere through more than one stack, 

you shall install the required CEMS, PM CPMS, and sorbent trap

monitoring systems described in each of the multiple stacks. You 

shall calculate hourly flow-weighted average pollutant emission 

rates for the unit as follows:

(i) Calculate the pollutant emission rate at each stack or duct 
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for each hour in which valid data are obtained for all 

parameters;

(ii) Multiply each calculated hourly pollutant emission rate at 

each stack or duct by the corresponding hourly stack gas flow 

rate at that stack or duct;

(iii) Sum the products determined under paragraph (a)(5)(iii)(B) 

of this section; and

(iv) Divide the result obtained in paragraph (a)(5)(iii)(c) of 

this section by the total hourly stack gas flow rate for the 

unit, summed across all of the stacks or ducts.

(b) If you use an oxygen (O2) or carbon dioxide (CO2) CEMS to 

convert measured pollutant concentrations to the units of the 

applicable emissions limit, the O2 or CO2 concentrations shall be 

monitored at a location that represents emissions to the 

atmosphere, i.e., at the outlet of the EGU, downstream of all 

emission control devices. You must install, certify, maintain, 

and operate the CEMS according to Part 75 of this chapter. Use 

only quality-assured O2 or CO2 data in the emissions 

calculations; do not use Part 75 substitute data values.

(c) If you are required to use a stack gas flow rate monitor, 

either for routine operation of a sorbent trap monitoring system 

or to convert pollutant concentrations to units of an electrical 

output-based emission standard in Table 1 or 2 to this subpart, 
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you must install, certify, operate, and maintain the monitoring 

system and conduct on-going quality-assurance testing of the 

system according to Part 75 of this chapter. Use only 

unadjusted, quality-assured flow rate data in the emissions 

calculations. Do not apply bias adjustment factors to the flow 

rate data and do not use substitute flow rate data in the 

calculations.

(d) If you are required to make corrections for stack gas 

moisture content when converting pollutant concentrations to the 

units of an emission standard in Table 1 of 2 to this subpart, 

you must install, certify, operate, and maintain a moisture 

monitoring system in accordance with Part 75 of this chapter. 

Alternatively, for coal-fired units, you may use appropriate 

fuel-specific default moisture values from §75.11(b) of this 

chapter to estimate the moisture content of the stack gas or you 

may petition the Administrator under §75.66 of this chapter for 

use of a default moisture value for non-coal-fired units. If you 

install and operate a moisture monitoring system, do not use 

substitute moisture data in the emissions calculations.

(e) If you use an HCl and/or HF CEMS, you must install, certify, 

operate, maintain, and quality-assure the data from the 

monitoring system in accordance with appendix B to this subpart. 

Calculate and record a 30-boiler operating day rolling average 
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HCl or HF emission rate in the units of the standard, updated 

after each new boiler operating day. Each 30-boiler operating 

day rolling average emission rate is the average of all the 

valid hourly HCl or HF emission rates in the preceding 30 boiler 

operating days (see section 9.4 of appendix B to this subpart). 

(f)(1) If you use an SO2 CEMS, you must install the monitor at 

the outlet of the EGU, downstream of all emission control 

devices, and you must certify, operate, and maintain the CEMS 

according to Part 75 of this chapter.

(2) For on-going QA, the SO2 CEMS must meet the applicable daily, 

quarterly, and semiannual or annual requirements in sections 2.1 

through 2.3 of appendix B to Part 75 of this chapter, with the 

following addition: You must perform the linearity checks 

required in section 2.2 of appendix B to Part 75 of this chapter 

if the SO2 CEMS has a span value of 30 ppm or less.

(3) Calculate and record a 30-boiler operating day rolling 

average SO2 emission rate in the units of the standard, updated 

after each new boiler operating day. Each 30-boiler operating 

day rolling average emission rate is the average of all of the 

valid SO2 emission rates in the preceding 30 boiler operating 

days.

(4) Use only unadjusted, quality-assured SO2 concentration values 

in the emissions calculations; do not apply bias adjustment 
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factors to the Part 75 SO2 data and do not use Part 75 substitute 

data values.

(g) If you use a Hg CEMS or a sorbent trap monitoring system, 

you must install, certify, operate, maintain and quality-assure 

the data from the monitoring system in accordance with appendix 

A to this subpart. You must calculate and record a 30-boiler

operating day rolling average Hg emission rate, in units of the 

standard, updated after each new boiler operating day. Each 30-

boiler operating day rolling average emission rate, calculated 

according to section 6.2 of appendix A to the subpart, is the 

average of all of the valid hourly Hg emission rates in the 

preceding 30 boiler operating days. Section 7.1.4.3 of appendix 

A to this subpart explains how to reduce sorbent trap monitoring 

system data to an hourly basis. 

(h) If you use a PM CPMS to demonstrate continuous compliance 

with an operating limit, you must install, calibrate, maintain, 

and operate the PM CPMS and record the output of the system as 

specified in paragraphs (h)(1) through (5) of this section.

(1) Install, calibrate, operate, and maintain your PM CPMS 

according to the procedures in your approved site-specific 

monitoring plan developed in accordance with §63.10005(d), and 

meet the requirements in section (h)(1)(i) through (iii) of this 

section.
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(i) The operating principle of the PM CPMS must be based on instack or extractive light scatter, light scintillation, beta 

attenuation, or mass accumulation detection of the exhaust gas 

or representative sample. The reportable measurement output from 

the PM CPMS may be expressed as milliamps, stack concentration, 

or other raw data signal.

(ii) The PM CPMS must have a cycle time (i.e., period required 

to complete sampling, measurement, and reporting for each 

measurement) no longer than 60 minutes.

(iii) The PM CPMS must be capable, at a minimum, of detecting 

and responding to particulate matter concentrations of 0.5 

mg/acm.

(2) For a new unit, complete the initial PM CPMS performance 

evaluation no later than [INSERT DATE 240 DAYS AFTER PUBLICATION 

OF THIS FINAL RULE IN THE FEDERAL REGISTER] or 180 days after 

the date of initial startup, whichever is later. For an existing 

unit, complete the initial performance evaluation no later than 

[INSERT DATES 3 YEARS AND 240 DAYS AFTER PUBLICATION OF THIS 

FINAL RULE IN THE FEDERAL REGISTER].

(3) Collect PM CPMS hourly average output data for all boiler 

operating hours except as indicated in section (h)(5) of this 

section. Express the PM CPMS output as milliamps, PM 

concentration, or other raw data signal value.
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(4) Calculate the arithmetic 30-boiler operating day rolling 

average of all of the hourly average PM CPMS output collected 

during all nonexempt boiler operating hours data (e.g., 

milliamps, PM concentration, raw data signal). 

(5) You must collect data using the PM CPMS at all times the 

process unit is operating and at the intervals specified in 

paragraph (h)(1)(ii) of this section, except for periods of 

monitoring system malfunctions, repairs associated with 

monitoring system malfunctions, required monitoring system 

quality assurance or quality control activities (including, as 

applicable, calibration checks and required zero and span 

adjustments), and any scheduled maintenance as defined in your 

site-specific monitoring plan.

(6) You must use all the data collected during all boiler 

operating hours in assessing the compliance with your operating 

limit except:

(i) Any data collected during monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, or 

required monitoring system quality assurance or quality control 

activities conducted during monitoring system malfunctions are 

not used in calculations (report any such periods in your annual 

deviation report);

(ii) Any data collected during periods when the monitoring 
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system is out of control as specified in your site-specific 

monitoring plan, repairs associated with periods when the 

monitoring system is out of control, or required monitoring 

system quality assurance or quality control activities conducted 

during out-of-control periods are not used in calculations 

(report emissions or operating levels and report any such 

periods in your annual deviation report);

(iii) Any data recorded during periods of startup or shutdown.

(7) You must record and make available upon request results of 

PM CPMS system performance audits, as well as the dates and 

duration of periods from when the PM CPMS is out of control 

until completion of the corrective actions necessary to return 

the PM CPMS to operation consistent with your site-specific 

monitoring plan.

(i) If you choose to comply with the PM filterable emissions 

limit in lieu of metal HAP limits, you may choose to install, 

certify, operate, and maintain a PM CEMS and record the output 

of the PM CEMS as specified in paragraphs (i)(1) through (5) of 

this section. The compliance limit will be expressed as a 30-

boiler operating day rolling average of the numerical emissions 

limit value applicable for your unit in tables 1 or 2.

(1) Install and certify your PM CEMS according to the procedures 

and requirements in Performance Specification 11 —
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Specifications and Test Procedures for Particulate Matter 

Continuous Emission Monitoring Systems at Stationary Sources in 

Appendix B to part 60 of this chapter, using Method 5 at 

Appendix A-3 to Part 60 of this chapter and ensuring that the 

front half filter temperature shall be 160o ± 14oC (320o ± 

25oF). The reportable measurement output from the PM CEMS must 

be expressed in units of the applicable emissions limit (e.g., 

lb/MMBtu, lb/MWh).

(2) Operate and maintain your PM CEMS according to the 

procedures and requirements in Procedure 2 — Quality Assurance 

Requirements for Particulate Matter Continuous Emission 

Monitoring Systems at Stationary Sources in Appendix F to Part 

60 of this chapter.

(i) You must conduct the relative response audit (RRA) for your

PM CEMS at least once annually.

(ii) You must conduct the relative correlation audit (RCA) for 

your PM CEMS at least once every 3 years.

(3) Collect PM CEMS hourly average output data for all boiler 

operating hours except as indicated in paragraph (i) of this 

section. 

(4) Calculate the arithmetic 30-boiler operating day rolling 

average of all of the hourly average PM CEMS output data 

collected during all nonexempt boiler operating hours. 
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(5) You must collect data using the PM CEMS at all times the 

process unit is operating and at the intervals specified in 

paragraph (a) of this section, except for periods of monitoring 

system malfunctions, repairs associated with monitoring system 

malfunctions, and required monitoring system quality assurance 

or quality control activities.

(i) You must use all the data collected during all boiler 

operating hours in assessing the compliance with your operating 

limit except:

(A) Any data collected during monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, or 

required monitoring system quality assurance or control 

activities conducted during monitoring system malfunctions in 

calculations and report any such periods in your annual 

deviation report;

(B) Any data collected during periods when the monitoring system 

is out of control as specified in your site-specific monitoring 

plan, repairs associated with periods when the monitoring system 

is out of control, or required monitoring system quality 

assurance or control activities conducted during out of control 

periods in calculations used to report emissions or operating 

levels and report any such periods in your annual deviation 

report;
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(C) Any data recorded during periods of startup or shutdown.

(ii) You must record and make available upon request results of 

PM CEMS system performance audits, dates and duration of periods 

when the PM CEMS is out of control to completion of the 

corrective actions necessary to return the PM CEMS to operation 

consistent with your site-specific monitoring plan.

(j) You may choose to comply with the metal HAP emissions limits

using CEMS approved in accordance with §63.7(f) as an 

alternative to the performance test method specified in this 

rule. If approved to use a HAP metals CEMS, the compliance limit 

will be expressed as a 30-boiler operating day rolling average 

of the numerical emissions limit value applicable for your unit 

in tables 1 or 2. If approved, you may choose to install, 

certify, operate, and maintain a HAP metals CEMS and record the 

output of the HAP metals CEMS as specified in paragraphs (j)(1) 

through (5) of this section.

(1) Install and certify your HAP metals CEMS according to the 

procedures and requirements in you approved site specific test 

plan as required in §63.7(e). The reportable measurement output 

from the HAP metals CEMS must be expressed in units of the 

applicable emissions limit (e.g., lb/MMBtu, lb/MWh) and in the 

form of a 30-boiler operating day rolling average.

(ii) Operate and maintain your HAP metals CEMS according to the 
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procedures and criteria in your site specific performance 

evaluation and quality control program plan required in 

§63.8(d).

(2) Collect HAP metals CEMS hourly average output data for all 

boiler operating hours except as indicated in section (4) of 

this section. 

(3) Calculate the arithmetic 30-boiler operating day rolling 

average of all of the hourly average HAP metals CEMS output data 

collected during all nonexempt boiler operating hours data. 

(4) You must collect data using the HAP metals CEMS at all times 

the process unit is operating and at the intervals specified in 

paragraph (a) of this section, except for periods of monitoring 

system malfunctions, repairs associated with monitoring system 

malfunctions, and required monitoring system quality assurance 

or quality control activities.

(i) You must use all the data collected during all boiler 

operating hours in assessing the compliance with your emission 

limit except:

(A) Any data collected during monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, or 

required monitoring system quality assurance or control 

activities conducted during monitoring system malfunctions in 

calculations and report any such periods in your annual 
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deviation report;

(B) Any data collected during periods when the monitoring system 

is out of control as specified in your site-specific monitoring 

plan, repairs associated with periods when the monitoring system 

is out of control, or required monitoring system quality 

assurance or control activities conducted during out of control 

periods in calculations used to report emissions or operating 

levels and report any such periods in your annual deviation 

report;

(C) Any data recorded during periods of startup or shutdown.

(ii) You must record and make available upon request results of 

HAP metals CEMS system performance audits, dates and duration of 

periods when the HAP metals CEMS is out of control to completion 

of the corrective actions necessary to return the HAP metals

CEMS to operation consistent with your site-specific performance 

evaluation and quality control program plan.

(k) If you demonstrate compliance with the HCl and HF emission 

limits for a liquid oil-fired EGU by conducting quarterly 

testing, you must also develop a site-specific monitoring plan 

as provided for in §63.10000(c)(2)(iii) and Table 7 to this 

subpart.

§63.10011 How do I demonstrate initial compliance with the 

emissions limits and work practice standards?
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(a) You must demonstrate initial compliance with each emissions 

limit that applies to you by conducting performance testing.

(b) If you are subject to an operating limit in Table 4, you 

demonstrate initial compliance with HAP metals or filterable PM 

emission limit(s) through performance stack tests and you elect 

to use a PM CPMS to demonstrate continuous performance, or if, 

for a liquid oil-fired unit, and you use quarterly stack testing 

for HCl and HF plus site-specific parameter monitoring to 

demonstrate continuous performance, you must also establish a

site-specific operating limit, in accordance with Table 4 to 

this subpart, §63.10007, and Table 6 to this subpart. You may 

use only the parametric data recorded during successful 

performance tests (i.e., tests that demonstrate compliance with 

the applicable emissions limits) to establish an operating 

limit.

(c)(1) If you use CEMS or sorbent trap monitoring systems to 

measure a HAP (e.g., Hg or HCl) directly, the first 30-boiler 

operating day rolling average emission rate obtained with 

certified CEMS after the applicable date in §63.9984 (or, if 

applicable, prior to that date, as described in 

§63.10005(b)(2)), expressed in units of the standard, is the 

initial performance test. Initial compliance is demonstrated if 

the results of the performance test meet the applicable emission 
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limit in Table 1 or 2 to this subpart. 

(2) For a unit that uses a CEMS to measure SO2 or PM emissions

for initial compliance, the first 30 boiler operating day 

average emission rate obtained with certified CEMS after the 

applicable date in §63.9984 (or, if applicable, prior to that 

date, as described in §63.10005(b)(2)), expressed in units of 

the standard, is the initial performance test. Initial 

compliance is demonstrated if the results of the performance 

test meet the applicable SO2 or filterable PM emission limit in 

Table 1 or 2 to this subpart.

(d) For candidate LEE units, use the results of the performance 

testing described in §63.10005(h) to determine initial 

compliance with the applicable emission limit(s) in Table 1 or 2 

to this subpart and to determine whether the unit qualifies for 

LEE status.

(e) You must submit a Notification of Compliance Status 

containing the results of the initial compliance demonstration, 

according to §63.10030(e).

(f)(1) You must determine the fuel whose combustion produces the 

least uncontrolled emissions, i.e., the cleanest fuel, either 

natural gas or distillate oil, that is available on site or 

accessible nearby for use during periods of startup or shutdown. 

(2) Your cleanest fuel, either natural gas or distillate oil,
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for use during periods of startup or shutdown determination may 

take safety considerations into account.

(g) You must follow the startup or shutdown requirements given 

in Table 3 for each coal-fired, liquid oil-fired, and solid oilderived fuel-fired EGU.

Continuous Compliance Requirements

§63.10020 How do I monitor and collect data to demonstrate 

continuous compliance?

(a) You must monitor and collect data according to this section 

and the site-specific monitoring plan required by §63.10000(d).

(b) You must operate the monitoring system and collect data at 

all required intervals at all times that the affected EGU is 

operating, except for periods of monitoring system malfunctions 

or out-of-control periods (see §63.8(c)(7) of this part), and 

required monitoring system quality assurance or quality control 

activities, including, as applicable, calibration checks and 

required zero and span adjustments. You are required to affect 

monitoring system repairs in response to monitoring system 

malfunctions and to return the monitoring system to operation as 

expeditiously as practicable.

(c) You may not use data recorded during EGU startup or shutdown 

or monitoring system malfunctions or monitoring system out-ofcontrol periods, repairs associated with monitoring system 
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malfunctions or monitoring system out-of-control periods, or 

required monitoring system quality assurance or control 

activities in calculations used to report emissions or operating 

levels. You must use all the data collected during all other 

periods in assessing the operation of the control device and 

associated control system.

(d) Except for periods of monitoring system malfunctions or 

monitoring system out-of-control periods, repairs associated 

with monitoring system malfunctions or monitoring system out-ofcontrol periods, and required monitoring system quality 

assurance or quality control activities including, as 

applicable, calibration checks and required zero and span 

adjustments), failure to collect required data is a deviation of 

the monitoring requirements.

§63.10021 How do I demonstrate continuous compliance with the 

emission limitations, operating limits, and work practice 

standards?

(a) You must demonstrate continuous compliance with each 

emissions limit, operating limit, and work practice standard in 

Tables 1 through 4 to this subpart that applies to you, 

according to the monitoring specified in Tables 6 and 7 to this 

subpart and paragraphs (b) through (g) of this section.

(b) Except as otherwise provided in §63.10020(c), if you use a 
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CEMS to measure SO2, PM, HCl, HF, or Hg emissions, or using a 

sorbent trap monitoring system to measure Hg emissions, you must 

demonstrate continuous compliance by using all quality-assured 

hourly data recorded by the CEMS (or sorbent trap monitoring 

system) and the other required monitoring systems (e.g., flow 

rate, CO2, O2, or moisture systems) to calculate the arithmetic 

average emissions rate in units of the standard on a continuous 

30-boiler operating day rolling average basis, updated at the 

end of each new boiler operating day. Use Equation 8 to 

determine the 30-boiler operating day rolling average.

30     =

∑ 







(. 8)

Where:

Heri is the hourly emissions rate for hour i and 

n is the number of hourly emissions rate values collected over 

30 boiler operating days.

(c) If you use a PM CPMS data to measure compliance with an 

operating limit in Table 4 to this subpart, you must record the 

PM CPMS output data for all periods when the process is 

operating and the PM CPMS is not out-of-control. You must 

demonstrate continuous compliance by using all quality-assured 

hourly average data collected by the PM CPMS for all operating 

hours to calculate the arithmetic average operating parameter in 

units of the operating limit (e.g., milliamps, PM concentration, 

raw data signal) on a 30 operating day rolling average basis, 
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updated at the end of each new boiler operating day. Use 

Equation 9 to determine the 30 boiler operating day average.

30     =

∑ 







(. 9)

where:

Hpvi is the hourly parameter value for hour i and 

n is the number of valid hourly parameter values collected over 

30 boiler operating days.

(d) If you use quarterly performance testing to demonstrate 

compliance with one or more applicable emissions limits in Table 

1 or 2 to this subpart, you 

(1) May skip performance testing in those quarters during which 

less than 168 boiler operating hours occur, except that a 

performance test must be conducted at least once every calendar 

year.

(2) Must conduct the performance test as defined in Table 5 to 

this subpart and calculate the results of the testing in units 

of the applicable emissions standard; and

(3) Must conduct site-specific monitoring for a liquid oil-fired 

unit to ensure compliance with the HCl and HF emission limits in 

Tables 1 and 2, in accordance with the requirements of 

§63.10000(c)(2)(iii). The monitoring must meet the general 

operating requirements provided in §63.10020(a).

(e) If you must conduct periodic performance tune-ups of your 

EGU(s), as specified in paragraphs (e)(1) through (9) of this 
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section, perform the first tune-up as part of your initial 

compliance demonstration. Notwithstanding this requirement, you 

may delay the first burner inspection until the next scheduled 

unit outage provided you meet the requirements of §63.10005. 

Subsequently, you must perform an inspection of the burner at 

least once every 36 calendar months unless your EGU employs 

neural network combustion optimization during normal operations 

in which case you must perform an inspection of the burner and 

combustion controls at least once every 48 calendar months. 

(i) As applicable, inspect the burner and combustion controls, 

and clean or replace any components of the burner or combustion 

controls as necessary upon initiation of the work practice 

program and at least once every required inspection period. 

Repair of a burner or combustion control component requiring

special order parts may be scheduled as follows:

(A) Burner or combustion control component parts needing 

replacement that affect the ability to optimize NOx and CO must 

be installed within 3 calendar months after the burner 

inspection,

(B) Burner or combustion control component parts that do not 

affect the ability to optimize NOx and CO may be installed on a 

schedule determined by the operator;

(2) As applicable, inspect the flame pattern and make any 
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adjustments to the burner or combustion controls necessary to 

optimize the flame pattern. The adjustment should be consistent 

with the manufacturer’s specifications, if available, or in 

accordance with best combustion engineering practice for that 

burner type;

(3) As applicable, observe the damper operations as a function 

of mill and/or cyclone loadings, cyclone and pulverizer coal 

feeder loadings, or other pulverizer and coal mill performance 

parameters, making adjustments and effecting repair to dampers, 

controls, mills, pulverizers, cyclones, and sensors;

(4) As applicable, evaluate windbox pressures and air 

proportions, making adjustments and effecting repair to dampers, 

actuators, controls, and sensors;

(5) Inspect the system controlling the air-to-fuel ratio and 

ensure that it is correctly calibrated and functioning properly. 

Such inspection may include calibrating excess O2 probes and/or 

sensors, adjusting overfire air systems, changing software 

parameters, and calibrating associated actuators and dampers to 

ensure that the systems are operated as designed. Any component 

out of calibration, in or near failure, or in a state that is 

likely to negate combustion optimization efforts prior to the 

next tune-up, should be corrected or repaired as necessary;

(6) Optimize combustion to minimize generation of CO and NOx. 
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This optimization should be consistent with the manufacturer’s 

specifications, if available, or best combustion engineering 

practice for the applicable burner type. NOx optimization 

includes burners, overfire air controls, concentric firing 

system improvements, neural network or combustion efficiency 

software, control systems calibrations, adjusting combustion 

zone temperature profiles, and add-on controls such as SCR and 

SNCR; CO optimization includes burners, overfire air controls, 

concentric firing system improvements, neural network or 

combustion efficiency software, control systems calibrations, 

and adjusting combustion zone temperature profiles;

(7) While operating at full load or the predominantly operated 

load, measure the concentration in the effluent stream of CO and 

NOx in ppm, by volume, and oxygen in volume percent, before and 

after the tune-up adjustments are made (measurements may be 

either on a dry or wet basis, as long as it is the same basis 

before and after the adjustments are made). You may use portable 

CO, NOx and O2 monitors for this measurement. EGU’s employing 

neural network optimization systems need only provide a single 

pre- and post-tune-up value rather than continual values before 

and after each optimization adjustment made by the system;

(8) Maintain on-site and submit, if requested by the 

Administrator, an annual report containing the information in 
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paragraphs (e)(1) through (e)(9) of this section including:

(i) The concentrations of CO and NOx in the effluent stream in 

ppm by volume, and oxygen in volume percent, measured before and 

after an adjustment of the EGU combustion systems;

(ii) A description of any corrective actions taken as a part of 

the combustion adjustment; and

(iii) The type(s) and amount(s) of fuel used over the 12 

calendar months prior to an adjustment, but only if the unit was 

physically and legally capable of using more than one type of 

fuel during that period; and

(9) Report the dates of the initial and subsequent tune-ups as 

follows:

(i) If the first required tune-up is performed as part of the 

initial compliance demonstration, report the date of the tune-up 

in hard copy (as specified in §63.10030) and electronically (as 

specified in §63.10031). Report the date of each subsequent 

tune-up electronically (as specified in §63.10031).

(ii) If the first tune-up is not conducted as part of the 

initial compliance demonstration, but is postponed until the 

next unit outage, report the date of that tune-up and all 

subsequent tune-ups electronically, in accordance with 

§63.10031. 

(f) You must submit the reports required under §63.10031 and, if 
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applicable, the reports required under appendices A and B to 

this subpart. The electronic reports required by appendices A 

and B to this subpart must be sent to the Administrator 

electronically in a format prescribed by the Administrator, as 

provided in §63.10031. CEMS data (except for PM CEMS and any 

approved alternative monitoring using a HAP metals CEMS) shall 

be submitted using EPA’s Emissions Collection and Monitoring 

Plan System (ECMPS) Client Tool. Other data, including PM CEMS 

data, HAP metals CEMS data, and CEMS performance test detail 

reports, shall be submitted in the file format generated through 

use of EPA’s Electronic Reporting Tool, the Compliance and 

Emissions Data Reporting Interface, or alternate electronic file 

format, all as provided for under §63.10031.

(g) You must report each instance in which you did not meet an 

applicable emissions limit or operating limit in Tables 1 

through 4 to this subpart or failed to conduct a required tuneup. These instances are deviations from the requirements of this 

subpart. These deviations must be reported according to 

§63.10031.

(h) You must keep records as specified in §63.10032 during 

periods of startup and shutdown.

(i) You must provide reports as specified in §63.10031 

concerning activities and periods of startup and shutdown.
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§63.10022 How do I demonstrate continuous compliance under the 

emissions averaging provision?

(a) Following the compliance date, the owner or operator must 

demonstrate compliance with this subpart on a continuous basis 

by meeting the requirements of paragraphs (a)(1) through (3) of 

this section.

(1) For each calendar month, demonstrate compliance with the 

average weighted emissions limit for the existing units 

participating in the emissions averaging option as determined in 

§63.10009(f) and (g);

(2) For each existing unit participating in the emissions 

averaging option that is equipped with PM CPMS, maintain the 

average parameter value at or below the operating limit 

established during the most recent performance test;

(3) For each existing unit participating in the emissions 

averaging option venting to a common stack configuration 

containing affected units from other subcategories, maintain the 

appropriate operating limit for each unit as specified in Table 

4 to this subpart that applies.

(b) Any instance where the owner or operator fails to comply 

with the continuous monitoring requirements in paragraphs (a)(1) 

through (3) of this section is a deviation.

§63.10023 How do I establish my PM CPMS operating limit and 
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determine compliance with it?

(a) During the initial performance test or any such subsequent 

performance test that demonstrates compliance with the 

filterable PM, individual non-mercury HAP metals, or total nonmercury HAP metals limit (or for liquid oil-fired units, 

individual HAP metals or total HAP metals limit, including Hg)

in Table 1 or 2, record all hourly average output values (e.g., 

milliamps, stack concentration, or other raw data signal) from 

the PM CPMS for the periods corresponding to the test runs 

(e.g., nine 1-hour average PM CPMS output values for three 3-

hour test runs). 

(b) Determine your operating limit as the highest 1-hour average 

PM CPMS output value recorded during the performance test. You 

must verify an existing or establish a new operating limit after 

each repeated performance test.

(c) You must operate and maintain your process and control 

equipment such that the 30 operating day average PM CPMS output 

does not exceed the operating limit determined in paragraphs (a) 

and (b) of this section.

Notification, Reports, and Records

§63.10030 What notifications must I submit and when?

(a) You must submit all of the notifications in §§63.7(b) and 

(c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that 
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apply to you by the dates specified.

(b) As specified in §63.9(b)(2), if you startup your affected 

source before [INSERT DATE 60 DAYS AFTER PUBLICATION OF THIS 

FINAL RULE IN THE FEDERAL REGISTER], you must submit an Initial 

Notification not later than 120 days after [INSERT DATE 60 DAYS 

AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER].

(c) As specified in §63.9(b)(4) and (b)(5), if you startup your 

new or reconstructed affected source on or after [INSERT DATE 60 

DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL 

REGISTER], you must submit an Initial Notification not later 

than 15 days after the actual date of startup of the affected 

source.

(d) When you are required to conduct a performance test, you 

must submit a Notification of Intent to conduct a performance 

test at least 30 days before the performance test is scheduled 

to begin.

(e) When you are required to conduct an initial compliance 

demonstration as specified in §63.10011(a), you must submit a 

Notification of Compliance Status according to §63.9(h)(2)(ii). 

The Notification of Compliance Status report must contain all 

the information specified in paragraphs (e)(1) through (7), as 

applicable.

(1) A description of the affected source(s) including 
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identification of which subcategory the source is in, the design 

capacity of the source, a description of the add-on controls 

used on the source, description of the fuel(s) burned, including 

whether the fuel(s) were determined by you or EPA through a 

petition process to be a non-waste under 40 CFR 241.3, whether 

the fuel(s) were processed from discarded non-hazardous 

secondary materials within the meaning of 40 CFR 241.3, and 

justification for the selection of fuel(s) burned during the 

performance test.

(2) Summary of the results of all performance tests and fuel 

analyses and calculations conducted to demonstrate initial 

compliance including all established operating limits.

(3) Identification of whether you plan to demonstrate compliance 

with each applicable emission limit through performance testing;

fuel moisture analyses; performance testing with operating

limits (e.g., use of PM CPMS); CEMS; or a sorbent trap 

monitoring system.

(4) Identification of whether you plan to demonstrate compliance 

by emissions averaging.

(5) A signed certification that you have met all applicable 

emission limits and work practice standards.

(6) If you had a deviation from any emission limit, work 

practice standard, or operating limit, you must also submit a 
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brief description of the deviation, the duration of the 

deviation, emissions point identification, and the cause of the 

deviation in the Notification of Compliance Status report.

(7) In addition to the information required in §63.9(h)(2), your 

notification of compliance status must include the following:

(i) A summary of the results of the annual performance tests and 

documentation of any operating limits that were reestablished 

during this test, if applicable. If you are conducting stack 

tests once every 3 years consistent with §63.10006(i), the date 

of the last three stack tests, a comparison of the emission 

level you achieved in the last three stack tests to the 50 

percent emission limit threshold required in §63.10006(i), and a 

statement as to whether there have been any operational changes 

since the last stack test that could increase emissions.

(ii) Certifications of compliance, as applicable, and must be 

signed by a responsible official stating:

(A) “This EGU complies with the requirements in §63.10021(a) to 

demonstrate continuous compliance.” and

(B) “No secondary materials that are solid waste were combusted 

in any affected unit.”

§63.10031 What reports must I submit and when?

(a) You must submit each report in Table 8 to this subpart that 

applies to you. If you are required to (or elect to) 
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continuously monitor Hg and/or HCl and/or HF emissions, you must 

also submit the electronic reports required under appendix A 

and/or appendix B to the subpart, at the specified frequency.

(b) Unless the Administrator has approved a different schedule 

for submission of reports under §63.10(a), you must submit each 

report by the date in Table 8 to this subpart and according to 

the requirements in paragraphs (b)(1) through (5) of this 

section.

(1) The first compliance report must cover the period beginning 

on the compliance date that is specified for your affected 

source in §63.9984 and ending on June 30 or December 31, 

whichever date is the first date that occurs at least 180 days 

after the compliance date that is specified for your source in 

§63.9984.

(2) The first compliance report must be postmarked or submitted 

electronically no later than July 31 or January 31, whichever 

date is the first date following the end of the first calendar 

half after the compliance date that is specified for your source 

in §63.9984.

(3) Each subsequent compliance report must cover the semiannual 

reporting period from January 1 through June 30 or the 

semiannual reporting period from July 1 through December 31.

(4) Each subsequent compliance report must be postmarked or 
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submitted electronically no later than July 31 or January 31, 

whichever date is the first date following the end of the 

semiannual reporting period.

(5) For each affected source that is subject to permitting 

regulations pursuant to part 70 or part 71 of this chapter, and 

if the permitting authority has established dates for submitting 

semiannual reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 

CFR 71.6(a)(3)(iii)(A), you may submit the first and subsequent 

compliance reports according to the dates the permitting 

authority has established instead of according to the dates in 

paragraphs (b)(1) through (4) of this section.

(c) The compliance report must contain the information required 

in paragraphs (c)(1) through (4) of this section.

(1) The information required by the summary report located in 

63.10(e)(3)(vi).

(2) The total fuel use by each affected source subject to an 

emission limit, for each calendar month within the semiannual 

reporting period, including, but not limited to, a description 

of the fuel, whether the fuel has received a non-waste 

determination by EPA or your basis for concluding that the fuel 

is not a waste, and the total fuel usage amount with units of 

measure.

(3) Indicate whether you burned new types of fuel during the 
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reporting period. If you did burn new types of fuel you must 

include the date of the performance test where that fuel was in 

use.

(4) Include the date of the most recent tune-up for each unit 

subject to the requirement to conduct a performance tune-up 

according to §63.10021(e). Include the date of the most recent 

burner inspection if it was not done annually and was delayed 

until the next scheduled unit shutdown.

(d) For each excess emissions occurring at an affected source 

where you are using a CMS to comply with that emission limit or 

operating limit, you must include the information required in

§63.10(e)(3)(v) in the compliance report specified in section 

(c). 

(e) Each affected source that has obtained a Title V operating 

permit pursuant to part 70 or part 71 of this chapter must 

report all deviations as defined in this subpart in the 

semiannual monitoring report required by 40 CFR 

70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected 

source submits a compliance report pursuant to Table 8 to this 

subpart along with, or as part of, the semiannual monitoring 

report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 

71.6(a)(3)(iii)(A), and the compliance report includes all 

required information concerning deviations from any emission 
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limit, operating limit, or work practice requirement in this 

subpart, submission of the compliance report satisfies any 

obligation to report the same deviations in the semiannual 

monitoring report. Submission of a compliance report does not 

otherwise affect any obligation the affected source may have to 

report deviations from permit requirements to the permit 

authority.

(f) As of January 1, 2012, and within 60 days after the date of 

completing each performance test, you must submit the results of 

the performance tests required by this subpart to EPA’s WebFIRE 

database by using the Compliance and Emissions Data Reporting 

Interface (CEDRI) that is accessed through EPA’s Central Data 

Exchange (CDX)(www.epa.gov/cdx). Performance test data must be 

submitted in the file format generated through use of EPA’s 

Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/index.html). Only data 

collected using those test methods on the ERT website are 

subject to this requirement for submitting reports 

electronically to WebFIRE. Owners or operators who claim that 

some of the information being submitted for performance tests is 

confidential business information (CBI) must submit a complete 

ERT file including information claimed to be CBI on a compact 

disk or other commonly used electronic storage media (including, 
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but not limited to, flash drives) to EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 

CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 

Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 

omitted must be submitted to EPA via CDX as described earlier in 

this paragraph. At the discretion of the delegated authority, 

you must also submit these reports, including the confidential 

business information, to the delegated authority in the format 

specified by the delegated authority. 

(1) Within 60 days after the date of completing each CEMS (SO2,

PM, HCl, HF, and Hg) performance evaluation test, as defined in 

§63.2 and required by this subpart, you must submit the relative 

accuracy test audit (RATA) data (or, for PM CEMS, RCA and RRA 

data) required by this subpart to EPA’s WebFIRE database by 

using the Compliance and Emissions Data Reporting Interface 

(CEDRI) that is accessed through EPA’s Central Data Exchange 

(CDX)(www.epa.gov/cdx). The RATA data shall be submitted in the 

file format generated through use of EPA’s Electronic Reporting 

Tool (ERT) (http://www.epa.gov/ttn/chief/ert/index.html). Only 

RATA data compounds listed on the ERT website are subject to 

this requirement. Owners or operators who claim that some of the 

information being submitted for RATAs is confidential business 

information (CBI) shall submit a complete ERT file including 
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information claimed to be CBI on a compact disk or other 

commonly used electronic storage media (including, but not 

limited to, flash drives) by registered letter to EPA and the 

same ERT file with the CBI omitted to EPA via CDX as described 

earlier in this paragraph. The compact disk or other commonly 

used electronic storage media shall be clearly marked as CBI and 

mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE 

Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. 

At the discretion of the delegated authority, owners or 

operators shall also submit these RATAs to the delegated 

authority in the format specified by the delegated authority. 

Owners or operators shall submit calibration error testing, 

drift checks, and other information required in the performance 

evaluation as described in §63.2 and as required in this 

chapter.

(2) For a PM CEMS, PM CPMS, or approved alternative monitoring 

using a HAP metals CEMS, within 60 days after the reporting 

periods ending on March 31st, June 30th, September 30th, and 

December 31st, you must submit quarterly reports to EPA’s WebFIRE 

database by using the Compliance and Emissions Data Reporting 

Interface (CEDRI) that is accessed through EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). You must use the appropriate

electronic reporting form in CEDRI or provide an alternate 
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electronic file consistent with EPA’s reporting form output 

format. For each reporting period, the quarterly reports must 

include all of the calculated 30-boiler operating day rolling 

average values derived from the CEMS and PM CPMS.

(3) Reports for an SO2 CEMS, a Hg CEMS or sorbent trap 

monitoring system, an HCl or HF CEMS, and any supporting 

monitors for such systems (such as a diluent or moisture monitor) 

shall be submitted using the ECMPS Client Tool, as provided for 

in Appendices A and B to this subpart and §63.10021(f).

(4) Submit the compliance reports required under paragraphs (c) 

and (d) of this section and the notification of compliance 

status required under §63.10030(e) to EPA’s WebFIRE database by 

using the Compliance and Emissions Data Reporting Interface 

(CEDRI) that is accessed through EPA’s Central Data Exchange 

(CDX)(www.epa.gov/cdx). You must use the appropriate electronic 

reporting form in CEDRI or provide an alternate electronic file 

consistent with EPA’s reporting form output format.

(5) All reports required by this subpart not subject to the 

requirements in paragraphs (f)(1) through (4) of this section 

must be sent to the Administrator at the appropriate address 

listed in §63.13. If acceptable to both the Administrator and 

the owner or operator of a source, these reports may be 

submitted on electronic media. The Administrator retains the 
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right to require submittal of reports subject to paragraphs

(f)(1), (2), and (3) of this section in paper format.

(g) If you had a malfunction during the reporting period, the 

compliance report must include the number, duration, and a brief 

description for each type of malfunction which occurred during 

the reporting period and which caused or may have caused any 

applicable emission limitation to be exceeded. 

§63.10032 What records must I keep?

(a) You must keep records according to paragraphs (a)(1) and (2) 

of this section. If you are required to (or elect to) 

continuously monitor Hg and/or HCl and/or HF emissions, you must 

also keep the records required under appendix A and/or appendix 

B to this subpart.

(1) A copy of each notification and report that you submitted to 

comply with this subpart, including all documentation supporting 

any Initial Notification or Notification of Compliance Status or 

semiannual compliance report that you submitted, according to 

the requirements in §63.10(b)(2)(xiv).

(2) Records of performance stack tests, fuel analyses, or other 

compliance demonstrations and performance evaluations, as 

required in §63.10(b)(2)(viii).

(b) For each CEMS and CPMS, you must keep records according to 

paragraphs (b)(1) through (4) of this section.
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(1) Records described in §63.10(b)(2)(vi) through (xi).

(2) Previous (i.e., superseded) versions of the performance 

evaluation plan as required in §63.8(d)(3).

(3) Request for alternatives to relative accuracy test for CEMS 

as required in §63.8(f)(6)(i).

(4) Records of the date and time that each deviation started and 

stopped, and whether the deviation occurred during a period of 

startup, shutdown, or malfunction or during another period.

(c) You must keep the records required in Table 7 to this 

subpart including records of all monitoring data and calculated 

averages for applicable PM CPMS operating limits to show 

continuous compliance with each emission limit and operating 

limit that applies to you.

(d) For each EGU subject to an emission limit, you must also 

keep the records in paragraphs (d)(1) through (3) of this 

section.

(1) You must keep records of monthly fuel use by each EGU, 

including the type(s) of fuel and amount(s) used.

(2) If you combust non-hazardous secondary materials that have 

been determined not to be solid waste pursuant to 40 CFR 

241.3(b)(1), you must keep a record which documents how the 

secondary material meets each of the legitimacy criteria. If you 

combust a fuel that has been processed from a discarded non-
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hazardous secondary material pursuant to 40 CFR 241.3(b)(2), you 

must keep records as to how the operations that produced the 

fuel satisfies the definition of processing in 40 CFR 241.2. If 

the fuel received a non-waste determination pursuant to the 

petition process submitted under 40 CFR 241.3(c), you must keep 

a record which documents how the fuel satisfies the requirements 

of the petition process.

(3) For an EGU that qualifies as an LEE under §63.10005(h), you 

must keep annual records that document that your emissions in 

the previous stack test(s) continue to qualify the unit for LEE 

status for an applicable pollutant, and document that there was 

no change in source operations including fuel composition and 

operation of air pollution control equipment that would cause 

emissions of the pollutant to increase within the past year.

(e) If you elect to average emissions consistent with §63.10009, 

you must additionally keep a copy of the emissions averaging 

implementation plan required in §63.10009(g), all calculations 

required under §63.10009, including daily records of heat input 

or steam generation, as applicable, and monitoring records 

consistent with §63.10022.

(f) You must keep records of the occurrence and duration of each 

startup and/or shutdown.

(g) You must keep records of the occurrence and duration of each 
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malfunction of an operation (i.e., process equipment) or the air 

pollution control and monitoring equipment.

(h) You must keep records of actions taken during periods of 

malfunction to minimize emissions in accordance with 

§63.10000(b), including corrective actions to restore 

malfunctioning process and air pollution control and monitoring 

equipment to its normal or usual manner of operation.

(i) You must keep records of the type(s) and amount(s) of fuel 

used during each startup or shutdown. 

(j) If you elect to establish that an EGU qualifies as a 

limited-use liquid oil-fired EGU, you must keep records of the 

type(s) and amount(s) of fuel use in each calendar quarter to 

document that the capacity factor limitation for that 

subcategory is met.

§63.10033 In what form and how long must I keep my records?

(a) Your records must be in a form suitable and readily 

available for expeditious review, according to §63.10(b)(1).

(b) As specified in §63.10(b)(1), you must keep each record for 

5 years following the date of each occurrence, measurement, 

maintenance, corrective action, report, or record.

(c) You must keep each record on site for at least 2 years after 

the date of each occurrence, measurement, maintenance, 

corrective action, report, or record, according to §63.10(b)(1). 
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You can keep the records off site for the remaining 3 years.

Other Requirements and Information

§63.10040 What parts of the General Provisions apply to me?

Table 9 to this subpart shows which parts of the General 

Provisions in §§63.1 through 63.15 apply to you.

§63.10041 Who implements and enforces this subpart?

(a) This subpart can be implemented and enforced by U.S. EPA, or 

a delegated authority such as your state, local, or tribal

agency. If the EPA Administrator has delegated authority to your 

state, local, or tribal agency, then that agency (as well as the 

U.S. EPA) has the authority to implement and enforce this 

subpart. You should contact your EPA Regional Office to find out 

if this subpart is delegated to your state, local, or tribal

agency.

(b) In delegating implementation and enforcement authority of 

this subpart to a state, local, or tribal agency under 40 CFR 

Part 63, subpart E, the authorities listed in paragraphs (b)(1) 

through (4) of this section are retained by the EPA 

Administrator and are not transferred to the state, local, or 

tribal agency; moreover, the U.S. EPA retains oversight of this 

subpart and can take enforcement actions, as appropriate, with 

respect to any failure by any person to comply with any 

provision of this subpart.
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(1) Approval of alternatives to the non-opacity emission limits 

and work practice standards in §63.9991(a) and (b) under 

§63.6(g).

(2) Approval of major change to test methods in Table 5 to this 

subpart under §63.7(e)(2)(ii) and (f) and as defined in §63.90, 

approval of minor and intermediate changes to monitoring 

performance specifications/procedures in Table 5 where the 

monitoring serves as the performance test method (see definition 

of “test method” in §63.2.

(3) Approval of major changes to monitoring under §63.8(f) and 

as defined in §63.90.

(4) Approval of major change to recordkeeping and reporting 

under §63.10(e) and as defined in §63.90.

§63.10042 What definitions apply to this subpart?

Terms used in this subpart are defined in the Clean Air Act 

(CAA), in §63.2 (the General Provisions), and in this section as 

follows:

Affirmative defense means, in the context of an enforcement 

proceeding, a response or defense put forward by a defendant, 

regarding which the defendant has the burden of proof, and the 

merits of which are independently and objectively evaluated in a 

judicial or administrative proceeding.

Anthracite coal means solid fossil fuel classified as anthracite 
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coal by American Society of Testing and Materials (ASTM) Method 

D388-05, “Standard Classification of Coals by Rank”

(incorporated by reference, see §63.14).

Bituminous coal means coal that is classified as bituminous 

according to ASTM Method D388-05, “Standard Classification of 

Coals by Rank” (incorporated by reference, see §63.14).

Boiler operating day means a 24-hour period between midnight and 

the following midnight during which any fuel is combusted at any 

time in the steam generating unit. It is not necessary for the 

fuel to be combusted the entire 24-hour period.

Capacity factor for a liquid oil-fired EGU means the total 

annual heat input from oil divided by the product of maximum 

hourly heat input for the EGU, regardless of fuel, multiplied by 

8,760 hours.

Coal means all solid fuels classifiable as anthracite, 

bituminous, sub-bituminous, or lignite by ASTM Method D388–05, 

“Standard Classification of Coals by Rank” (incorporated by 

reference, see §63.14), and coal refuse. Synthetic fuels derived 

from coal for the purpose of creating useful heat including but 

not limited to, coal derived gases (not meeting the definition 

of natural gas), solvent-refined coal, coal-oil mixtures, and 

coal-water mixtures, are considered “coal” for the purposes of 

this subpart.
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Coal-fired electric utility steam generating unit means an 

electric utility steam generating unit meeting the definition of 

“fossil fuel-fired” that burns coal for more than 10.0 percent 

of the average annual heat input during any 3 consecutive 

calendar years or for more than 15.0 percent of the annual heat 

input during any one calendar year.

Coal refuse means any by-product of coal mining, physical coal 

cleaning, and coal preparation operations (e.g., culm, gob, 

etc.) containing coal, matrix material, clay, and other organic 

and inorganic material with an ash content greater than 50 

percent (by weight) and a heating value less than 13,900 

kilojoules per kilogram (6,000 Btu per pound) on a dry basis.

Cogeneration means a steam-generating unit that simultaneously 

produces both electrical and useful thermal (or mechanical) 

energy from the same primary energy source.

Cogeneration unit means a stationary, fossil fuel-fired EGU 

meeting the definition of “fossil fuel-fired” or stationary, 

integrated gasification combined cycle:

(1) Having equipment used to produce electricity and useful 

thermal energy for industrial, commercial, heating, or cooling 

purposes through the sequential use of energy; and

(2) Producing during the 12-month period starting on the date 

the unit first produces electricity and during any calendar year 
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after which the unit first produces electricity:

(i) For a topping-cycle cogeneration unit,

(A) Useful thermal energy not less than 5 percent of total 

energy output; and

(B) Useful power that, when added to one-half of useful thermal 

energy produced, is not less than 42.5 percent of total energy 

input, if useful thermal energy produced is 15 percent or more 

of total energy output, or not less than 45 percent of total 

energy input, if useful thermal energy produced is less than 15 

percent of total energy output.

(ii) For a bottoming-cycle cogeneration unit, useful power not 

less than 45 percent of total energy input.

(3) Provided that the total energy input under paragraphs 

(2)(i)(B) and (2)(ii) of this definition shall equal the unit’s 

total energy input from all fuel except biomass if the unit is a 

boiler.

Combined-cycle gas stationary combustion turbine means a 

stationary combustion turbine system where heat from the turbine 

exhaust gases is recovered by a waste heat boiler.

Common stack means the exhaust of emissions from two or more 

affected units through a single flue.

Continental liquid oil-fired subcategory means any oil-fired 

electric utility steam generating unit that burns liquid oil and 
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is located in the continental United States.

Deviation means any instance in which an affected source subject 

to this subpart, or an owner or operator of such a source:

(i) Fails to meet any requirement or obligation established by 

this subpart including, but not limited to, any emission limit, 

operating limit, work practice standard, or monitoring 

requirement; or

(ii) Fails to meet any term or condition that is adopted to 

implement an applicable requirement in this subpart and that is 

included in the operating permit for any affected source 

required to obtain such a permit.

A deviation is not always a violation. The determination of 

whether a deviation constitutes a violation of the standard is 

up to the discretion of the entity responsible for enforcement 

of the standards.

Distillate oil means fuel oils, including recycled oils, that 

comply with the specifications for fuel oil numbers 1 and 2, as 

defined by ASTM Method D396–10, “Standard Specification for Fuel 

Oils” (incorporated by reference, see §63.14).

Dry flue gas desulfurization technology, or dry FGD, or spray 

dryer absorber (SDA), or spray dryer, or dry scrubber means an 

add-on air pollution control system located downstream of the 

steam generating unit that injects a dry alkaline sorbent (dry 
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sorbent injection) or sprays an alkaline sorbent slurry (spray 

dryer) to react with and neutralize acid gases such as SO2 and 

HCl in the exhaust stream forming a dry powder material. 

Alkaline sorbent injection systems in fluidized bed combustors 

(FBC) or circulating fluidized bed (CFB) boilers are included in 

this definition.

Dry sorbent injection (DSI) means an add-on air pollution 

control system in which sorbent (e.g., conventional activated 

carbon, brominated activated carbon, Trona, hydrated lime, 

sodium carbonate, etc.) is injected into the flue gas steam 

upstream of a PM control device to react with and neutralize 

acid gases (such as SO2 and HCl) or Hg in the exhaust stream 

forming a dry powder material that may be removed in a primary 

or secondary PM control device.

Electric Steam generating unit means any furnace, boiler, or 

other device used for combusting fuel for the purpose of 

producing steam (including fossil-fuel-fired steam generators 

associated with integrated gasification combined cycle gas 

turbines; nuclear steam generators are not included) for the 

purpose of powering a generator to produce electricity or 

electricity and other thermal energy.

Electric utility steam generating unit (EGU) means a fossil 

fuel-fired combustion unit of more than 25 megawatts electric 
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(MWe) that serves a generator that produces electricity for 

sale. A fossil fuel-fired 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 considered an 

electric utility steam generating unit.

Emission limitation means any emissions limit, work practice 

standard, or operating limit.

Excess emissions means, with respect to this subpart, results of 

any required measurements outside the applicable range (e.g., 

emissions limitations, parametric operating limits) that is 

permitted by this subpart. The values of measurements will be in 

the same units and averaging time as the values specified in 

this subpart for the limitations.

Federally enforceable means all limitations and conditions that 

are enforceable by the Administrator, including the requirements 

of 40 CFR parts 60, 61, and 63; requirements within any 

applicable state implementation plan; and any permit 

requirements established under 40 CFR 52.21 or under 40 CFR 

51.18 and 40 CFR 51.24.

Flue gas desulfurization system means any add-on air pollution 

control system located downstream of the steam generating unit 

whose purpose or effect is to remove at least 50 percent of the 
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SO2 in the exhaust gas stream.

Fossil fuel means natural gas, oil, coal, and any form of solid, 

liquid, or gaseous fuel derived from such material.

Fossil fuel-fired means an electric utility steam generating 

unit (EGU) that is capable of combusting more than 25 MW of 

fossil fuels. To be “capable of combusting” fossil fuels, an EGU 

would need to have these fuels allowed in its operating permit

and have the appropriate fuel handling facilities on-site or 

otherwise available (e.g., coal handling equipment, including 

coal storage area, belts and conveyers, pulverizers, etc.; oil 

storage facilities). In addition, fossil fuel-fired means any 

EGU that fired fossil fuels for more than 10.0 percent of the 

average annual heat input during any 3 consecutive calendar 

years or for more than 15.0 percent of the annual heat input 

during any one calendar year after the applicable compliance 

date.

Fuel type means each category of fuels that share a common name 

or classification. Examples include, but are not limited to, 

bituminous coal, subbituminous coal, lignite, anthracite, 

biomass, and residual oil. Individual fuel types received from 

different suppliers are not considered new fuel types.

Fluidized bed boiler, or fluidized bed combustor, or circulating 

fluidized boiler, or CFB means a boiler utilizing a fluidized
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bed combustion process.

Fluidized bed combustion means a process where a fuel is burned 

in a bed of granulated particles which are maintained in a 

mobile suspension by the upward flow of air and combustion 

products.

Gaseous fuel includes, but is not limited to, natural gas, 

process gas, landfill gas, coal derived gas, solid oil-derived 

gas, refinery gas, and biogas. 

Generator means a device that produces electricity.

Gross output means the gross useful work performed by the steam 

generated and, for an IGCC electric utility steam generating 

unit, the work performed by the stationary combustion turbines. 

For a unit generating only electricity, the gross useful work 

performed is the gross electrical output from the unit’s 

turbine/generator sets. For a cogeneration unit, the gross 

useful work performed is the gross electrical output, including 

any such electricity used in the power production process (which 

process includes, but is not limited to, any on-site processing 

or treatment of fuel combusted at the unit and any on-site 

emission controls), or mechanical output plus 75 percent of the 

useful thermal output measured relative to ISO conditions that 

is not used to generate additional electrical or mechanical 

output or to enhance the performance of the unit (i.e., steam 
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delivered to an industrial process).

Heat input means heat derived from combustion of fuel in an EGU 

(synthetic gas for an IGCC) and does not include the heat input 

from preheated combustion air, recirculated flue gases, or 

exhaust gases from other sources such as gas turbines, internal 

combustion engines, etc.

Integrated gasification combined cycle electric utility steam 

generating unit or IGCC means an electric utility steam 

generating unit meeting the definition of “fossil fuel-fired”

that burns a synthetic gas derived from coal and/or solid oilderived fuel for more than 10.0 percent of the average annual 

heat input during any 3 consecutive calendar years or for more 

than 15.0 percent of the annual heat input during any one 

calendar year in a combined-cycle gas turbine. No solid coal or 

solid oil-derived fuel is directly burned in the unit during 

operation.

ISO conditions means a temperature of 288 Kelvin, a relative 

humidity of 60 percent, and a pressure of 101.3 kilopascals.

Lignite coal means coal that is classified as lignite A or B 

according to ASTM Method D388-05, “Standard Classification of 

Coals by Rank” (incorporated by reference, see §63.14).

Limited-use liquid oil-fired subcategory means an oil-fired 

electric utility steam generating unit with an annual capacity 
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factor of less than 8 percent of its maximum or nameplate heat 

input, whichever is greater, averaged over a 24-month block 

contiguous period commencing [INSERT DATE 60 DAYS AND 3 YEARS 

AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER].

Liquid fuel includes, but is not limited to, distillate oil and 

residual oil.

Monitoring system malfunction or out of control period means any 

sudden, infrequent, not reasonably preventable failure of the 

monitoring system to provide valid data. Monitoring system 

failures that are caused in part by poor maintenance or careless 

operation are not malfunctions.

Natural gas means a naturally occurring fluid mixture of 

hydrocarbons (e.g., methane, ethane, or propane) produced in 

geological formations beneath the Earth’s surface that maintains 

a gaseous state at standard atmospheric temperature and pressure 

under ordinary conditions. Natural gas contains 20.0 grains or 

less of total sulfur per 100 standard cubic feet. Additionally, 

natural gas must either be composed of at least 70 percent 

methane by volume or have a gross calorific value between 950 

and 1,100 Btu per standard cubic foot. Natural gas does not 

include the following gaseous fuels: landfill gas, digester gas, 

refinery gas, sour gas, blast furnace gas, coal-derived gas, 

producer gas, coke oven gas, or any gaseous fuel produced in a 
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process which might result in highly variable sulfur content or 

heating value.

Natural gas-fired electric utility steam generating unit means 

an electric utility steam generating unit meeting the definition 

of “fossil fuel-fired” that is not a coal-fired, oil-fired, or 

IGCC electric utility steam generating unit and that burns 

natural gas for more than 10.0 percent of the average annual 

heat input during any 3 consecutive calendar years or for more 

than 15.0 percent of the annual heat input during any one 

calendar year.

Net-electric output means the gross electric sales to the 

utility power distribution system minus purchased power on a 

calendar year basis.

Non-continental area means the State of Hawaii, the Virgin 

Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, 

or the Northern Mariana Islands.

Non-continental liquid oil-fired subcategory means any oil-fired 

electric utility steam generating unit that burns liquid oil and 

is located outside the continental United States.

Non-mercury (Hg) HAP metals means Antimony (Sb), Arsenic (As), 

Beryllium (Be), Cadmium (Cd), Chromium (Cr), Cobalt (Co), Lead 

(Pb), Manganese (Mn), Nickel (Ni), and Selenium (Se).

Oil means crude oil or petroleum or a fuel derived from crude 
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oil or petroleum, including distillate and residual oil, solid 

oil-derived fuel (e.g., petroleum coke) and gases derived from 

solid oil-derived fuels (not meeting the definition of natural 

gas).

Oil-fired electric utility steam generating unit means an 

electric utility steam generating unit meeting the definition of 

“fossil fuel-fired” that is not a coal-fired electric utility 

steam generating unit and that burns oil for more than 10.0 

percent of the average annual heat input during any 3 

consecutive calendar years or for more than 15.0 percent of the 

annual heat input during any one calendar year.

Particulate matter or PM means any finely divided solid material 

as measured by the test methods specified under this subpart, or 

an alternative method.

Pulverized coal (PC) boiler means an EGU in which pulverized 

coal is introduced into an air stream that carries the coal to 

the combustion chamber of the EGU where it is fired in 

suspension.

Residual oil means crude oil, and all fuel oil numbers 4, 5 and 

6, as defined by ASTM Method D396–10, “Standard Specification 

for Fuel Oils” (incorporated by reference, see §63.14).

Responsible official means responsible official as defined in 40 

CFR 70.2.
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Shutdown means the cessation of operation of a boiler for any 

purpose. Shutdown begins either when none of the steam from the 

boiler is used to generate electricity for sale over the grid or 

for any other purpose (including on-site use), or at the point 

of no fuel being fired in the boiler, whichever is earlier.

Shutdown ends when there is both no electricity being generated 

and no fuel being fired in the boiler.

Startup means either the first-ever firing of fuel in a boiler 

for the purpose of producing electricity, or the firing of fuel 

in a boiler after a shutdown event for any purpose. Startup ends 

when any of the steam from the boiler is used to generate 

electricity for sale over the grid or for any other purpose 

(including on-site use).

Stationary combustion turbine means all equipment, including but 

not limited to the turbine, the fuel, air, lubrication and 

exhaust gas systems, control systems (except emissions control 

equipment), and any ancillary components and sub-components 

comprising any simple cycle stationary combustion turbine, any 

regenerative/recuperative cycle stationary combustion turbine, 

the combustion turbine portion of any stationary cogeneration 

cycle combustion system, or the combustion turbine portion of 

any stationary combined cycle steam/electric generating system. 

Stationary means that the combustion turbine is not self 
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propelled or intended to be propelled while performing its 

function. Stationary combustion turbines do not include turbines 

located at a research or laboratory facility, if research is 

conducted on the turbine itself and the turbine is not being 

used to power other applications at the research or laboratory 

facility.

Steam generating unit means any furnace, boiler, or other device 

used for combusting fuel for the purpose of producing steam 

(including fossil-fuel-fired steam generators associated with 

integrated gasification combined cycle gas turbines; nuclear 

steam generators are not included).

Stoker means a unit consisting of a mechanically operated fuel 

feeding mechanism, a stationary or moving grate to support the 

burning of fuel and admit undergrate air to the fuel, an 

overfire air system to complete combustion, and an ash discharge 

system. There are two general types of stokers: underfeed and 

overfeed. Overfeed stokers include mass feed and spreader 

stokers.

Subbituminous coal means coal that is classified as 

subbituminous A, B, or C according to ASTM Method D388-05, 

“Standard Classification of Coals by Rank” (incorporated by 

reference, see §63.14).

Unit designed for coal > 8,300 Btu/lb subcategory means any 
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coal-fired EGU that is not a coal-fired EGU in the “unit 

designed for low rank virgin coal” subcategory.

Unit designed for low rank virgin coal subcategory means any 

coal-fired EGU that is designed to burn and that is burning 

nonagglomerating virgin coal having a calorific value (moist, 

mineral matter-free basis) of less than 19,305 kJ/kg (8,300 

Btu/lb) that is constructed and operates at or near the mine 

that produces such coal.

Unit designed to burn solid oil-derived fuel subcategory means 

any oil-fired EGU that burns solid oil-derived fuel.

Voluntary consensus standards or VCS mean technical standards 

(e.g., materials specifications, test methods, sampling 

procedures, business practices) developed or adopted by one or 

more voluntary consensus bodies. The EPA/OAQPS has by precedent 

only used VCS that are written in English. Examples of VCS 

bodies are: American Society of Testing and Materials (ASTM), 

American Society of Mechanical Engineers (ASME), International 

Standards Organization (ISO), Standards Australia (AS), British 

Standards (BS), Canadian Standards (CSA), European Standard (EN 

or CEN) and German Engineering Standards (VDI). The types of 

standards that are not considered VCS are standards developed 

by: the U.S. states, e.g., California (CARB) and Texas (TCEQ); 

industry groups, such as American Petroleum Institute (API), Gas 
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Processors Association (GPA), and Gas Research Institute (GRI); 

and other branches of the U.S. government, e.g., Department of 

Defense (DOD) and Department of Transportation (DOT). This does 

not preclude EPA from using standards developed by groups that 

are not VCS bodies within an EPA rule. When this occurs, EPA has 

done searches and reviews for VCS equivalent to these non-VCS

methods.

Wet flue gas desulfurization technology, or wet FGD, or wet 

scrubber means any add-on air pollution control device that is 

located downstream of the steam generating unit that mixes an 

aqueous stream or slurry with the exhaust gases from an EGU to 

control emissions of PM and/or to absorb and neutralize acid 

gases, such as SO2 and HCl.

Work practice standard means any design, equipment, work 

practice, or operational standard, or combination thereof, which 

is promulgated pursuant to CAA section 112(h).

Tables to Subpart UUUUU of Part 63

Table 1 to Subpart UUUUU of Part 63 — Emission Limits for New or 

Reconstructed EGUs

As stated in §63.9991, you must comply with the following 

applicable emission limits:

If your EGU 

is in this 

subcategory 

...

For the following 

pollutants ...

You must meet the 

following emission 

limits and work 

practice standards 

...

Using these 

requirements, 

as appropriate 

(e.g., 

specified 

sampling 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 982 of 1103

volume or test 

run duration)

and 

limitations

with the test 

methods in 

Table 5...

1. Coal-fired 

unit not low 

rank virgin 

coal.

a. Filterable 

particulate 

matter (PM)

7.0E-3 lb/MWh1 Collect a 

minimum of 4 

dscm per run.

OR OR

Total non-Hg HAP 

metals

6.0E-2 lb/GWh Collect a 

minimum of 4 

dscm per run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-3 lb/GWh

3.0E-3 lb/GWh

6.0E-4 lb/GWh

4.0E-4 lb/GWh

7.0E-3 lb/GWh

2.0E-3 lb/GWh

2.0E-3 lb/GWh

4.0E-3 lb/GWh

4.0E-2 lb/GWh 

6.0E-3 lb/GWh

Collect a 

minimum of 3

dscm per run.

b. Hydrogen 

chloride (HCl)

4.0E-4 lb/MWh For Method 

26A, collect a 

minimum of 3

dscm per run. 

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR

Sulfur dioxide 

(SO2)

3

4.0E-1 lb/MWh SO2 CEMS.

c. Mercury (Hg) 2.0E-4 lb/GWh Hg CEMS or 

sorbent trap 
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Page 983 of 1103

monitoring 

system only.

2. Coal-fired 

units low 

rank virgin 

coal.

a. Filterable 

particulate 

matter (PM)

7.0E-3 lb/MWh1 Collect a 

minimum of 4 

dscm per run.

OR OR

Total non-Hg HAP 

metals

6.0E-2 lb/GWh Collect a 

minimum of 4 

dscm per run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-3 lb/GWh

3.0E-3 lb/GWh

6.0E-4 lb/GWh

4.0E-4 lb/GWh

7.0E-3 lb/GWh

2.0E-3 lb/GWh

2.0E-3 lb/GWh

4.0E-3 lb/GWh

4.0E-2 lb/GWh 

6.0E-3 lb/GWh

Collect a 

minimum of 3

dscm per run.

b. Hydrogen 

chloride (HCl)

4.0E-4 lb/MWh For Method 

26A, collect a 

minimum of 3

dscm per run.

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR

Sulfur dioxide 

(SO2)

3

4.0E-1 lb/MWh SO2 CEMS.

c. Mercury (Hg) 4.0E-2 lb/GWh Hg CEMS or 

sorbent trap 

monitoring 

system only.

3. IGCC unit. a. Filterable 

particulate 

matter (PM)

7.0E-2 lb/MWh4

9.0E-2 lb/MWh5

Collect a 

minimum of 1 

dscm per run.
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Page 984 of 1103

OR OR

Total non-Hg HAP 

metals

4.0E-1 lb/GWh Collect a 

minimum of 1

dscm per run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

2.0E-2 lb/GWh

2.0E-2 lb/GWh

1.0E-3 lb/GWh

2.0E-3 lb/GWh

4.0E-2 lb/GWh

4.0E-3 lb/GWh

9.0E-3 lb/GWh

2.0E-2 lb/GWh

7.0E-2 lb/GWh 

3.0E-1 lb/GWh

Collect a 

minimum of 2

dscm per run.

b. Hydrogen 

chloride (HCl)

2.0E-3 lb/MWh For Method 

26A, collect a 

minimum of 1 

dscm per run; 

for Method 26, 

collect a 

minimum of 120

liters per 

run. 

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR

Sulfur dioxide 

(SO2)

3

4.0E-1 lb/MWh SO2 CEMS.

c. Mercury (Hg) 3.0E-3 lb/GWh Hg CEMS or 

sorbent trap 

monitoring 

system only.

4. Liquid 

oil-fired 

unit –

continental

a. Filterable 

particulate 

matter (PM)

7.0E-2 lb/MWh1 Collect a 

minimum of 1 

dscm per run.

OR OR
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 985 of 1103

(excluding 

limited-use 

liquid oilfired 

subcategory 

units).

Total HAP metals 2.0E-4 lb/MWh Collect a 

minimum of 2

dscm per run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

1.0E-2 lb/GWh

3.0E-3 lb/GWh

5.0E-4 lb/GWh

2.0E-4 lb/GWh

2.0E-2 lb/GWh

3.0E-2 lb/GWh

8.0E-3 lb/GWh

2.0E-2 lb/GWh

9.0E-2 lb/GWh

2.0E-2 lb/GWh

Collect a 

minimum of 2

dscm per run.

Mercury (Hg) 1.0E-4 lb/GWh For Method 30B 

sample volume 

determination 

(Section 

8.2.4), the 

estimated Hg 

concentration 

should 

nominally be < 

1⁄2 the 

standard.

b. Hydrogen 

chloride (HCl)

4.0E-4 lb/MWh For Method 

26A, collect a 

minimum of 3 

dscm per run. 

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

c. Hydrogen 

fluoride (HF)

4.0E-4 lb/MWh For Method 

26A, collect a 

minimum of 3 

dscm per run. 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 986 of 1103

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

5. Liquid 

oil-fired 

unit – noncontinental

(excluding 

limited-use 

liquid oilfired 

subcategory 

units).

a. Filterable 

particulate 

matter (PM)

2.0E-1 lb/MWh1 Collect a 

minimum of 1 

dscm per run.

OR OR

Total HAP metals 7.0E-3 lb/MWh Collect a 

minimum of 1

dscm per run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-3 lb/GWh

6.0E-2 lb/GWh

2.0E-3 lb/GWh

2.0E-3 lb/GWh

2.0E-2 lb/GWh

3.0E-1 lb/GWh

3.0E-2 lb/GWh

1.0E-1 lb/GWh

4.1E0 lb/GWh

2.0E-2 lb/GWh

Collect a 

minimum of 3

dscm per run.

Mercury (Hg) 4.0E-4 lb/GWh For Method 30B 

sample volume 

determination 

(Section 

8.2.4), the 

estimated Hg 

concentration 

should 

nominally be < 

1⁄2 the 

standard.

b. Hydrogen 

chloride (HCl)

2.0E-3 lb/MWh For Method 

26A, collect a 

minimum of 1 

dscm per run; 

for Method 26, 

collect a 

minimum of 120
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 987 of 1103

liters per 

run. 

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

c. Hydrogen 

fluoride (HF)

5.0E-4 lb/MWh For Method 

26A, collect a 

minimum of 3 

dscm per run. 

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

6. Solid oilderived fuelfired unit.a. Filterable 

particulate 

matter (PM)

2.0E-2 lb/MWh1 Collect a 

minimum of 1 

dscm per run.

OR OR

Total non-Hg HAP 

metals

6.0E-1 lb/GWh Collect a 

minimum of 1

dscm per run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-3 lb/GWh

3.0E-3 lb/GWh

6.0E-4 lb/GWh

7.0E-4 lb/GWh

6.0E-3 lb/GWh

2.0E-3 lb/GWh

2.0E-2 lb/GWh

7.0E-3 lb/GWh

4.0E-2 lb/GWh

6.0E-3 lb/GWh

Collect a 

minimum of 3

dscm per run.

b. Hydrogen 

chloride (HCl)

4.0E-4 lb/MWh For Method 

26A, collect a 

minimum of 3

dscm per run. 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 988 of 1103

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR

Sulfur dioxide 

(SO2)

3

4.0E-1 lb/MWh SO2 CEMS.

c. Mercury (Hg) 2.0E-3 lb/GWh Hg CEMS or 

Sorbent trap 

monitoring 

system only.

1 Gross electric output.

2 Incorporated by reference, see §63.14.

3 You may not use the alternate SO2 limit if your EGU does not 

have some form of FGD system and SO2 CEMS installed.

4 Duct burners on syngas; gross electric output.

5 Duct burners on natural gas; gross electric output

Table 2 to Subpart UUUUU of Part 63 — Emission Limits for 

Existing EGUs

As stated in §63.9991, you must comply with the following 

applicable emission limits:1

If your EGU is 

in this 

subcategory ...

For the 

following 

pollutants ...

You must meet the 

following emission 

limits and work 

practice standards 

...

Using these 

requirement

s, as 

appropriate 

(e.g., 

specified 

sampling 

volume or 

test run 

duration)

and 

limitations

with the 

test 

methods in 

Table 5...

1. Coal-fired a. Filterable 3.0E-2 lb/MMBtu or Collect a 
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Page 989 of 1103

unit not low 

rank virgin 

coal.

particulate 

matter (PM)

3.0E-1 lb/MWh2 minimum of 

1 dscm per 

run.

OR OR

Total non-Hg 

HAP metals

5.0E-5 lb/MMBtu

5.0E-1 lb/GWh

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-1 lb/TBtu or

8.0E-3 lb/GWh

1.1E0 lb/TBtu or

2.0E-2 lb/GWh

2.0E-1 lb/TBtu or

2.0E-3 lb/GWh

3.0E-1 lb/TBtu or

3.0E-3 lb/GWh

2.8E0 lb/TBtu or

3.0E-2 lb/GWh

8.0E-1 lb/TBtu or

8.0E-3 lb/GWh

1.2E0 lb/TBtu or

2.0E-2 lb/GWh

4.0E0 lb/TBtu or

5.0E-2 lb/GWh

3.5E0 lb/TBtu or

4.0E-2 lb/GWh

5.0E0 lb/TBtu or

6.0E-2 lb/GWh

Collect a 

minimum of 

3 dscm per 

run.

b. Hydrogen 

chloride (HCl)

2.0E-3 lb/MMBtu or

2.0E-2 lb/MWh

For Method 

26A, 

collect a 

minimum of 

0.75 dscm 

per run; 

for Method 

26, collect 

a minimum 

of 120

liters per 

run. 

For ASTM 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 990 of 1103

D6348-033

or Method 

320, sample 

for a 

minimum of 

1 hour.

OR

Sulfur dioxide 

(SO2)

4

2.0E-1 lb/MMBtu or

1.5E0 lb/MWh

SO2 CEMS.

c. Mercury (Hg) 1.2E0 lb/TBtu or

1.3E-2 lb/GWh

LEE Testing 

for 30 days 

with 10 

days 

maximum per 

Method 30B 

run or Hg 

CEMS or 

sorbent 

trap 

monitoring 

system

only.

2. Coal-fired 

unit low rank 

virgin coal.

a. Filterable 

particulate 

matter (PM)

3.0E-2 lb/MMBtu or 

3.0E-1 lb/MWh2

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Total non-Hg 

HAP metals

5.0E-5 lb/MMBtu or

5.0E-1 lb/GWh

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

8.0E-1 lb/TBtu or

8.0E-3 lb/GWh

1.1E0 lb/TBtu or

2.0E-2 lb/GWh

2.0E-1 lb/TBtu or

2.0E-3 lb/GWh

3.0E-1 lb/TBtu or

3.0E-3 lb/GWh

2.8E0 lb/TBtu or

3.0E-2 lb/GWh

Collect a 

minimum of 

3 dscm per 

run.
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 991 of 1103

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-1 lb/TBtu or

8.0E-3 lb/GWh

1.2E0 lb/TBtu or

2.0E-2 lb/GWh

4.0E0 lb/TBtu or

5.0E-2 lb/GWh

3.5E0 lb/TBtu or

4.0E-2 lb/GWh

5.0E0 lb/TBtu or

6.0E-2 lb/GWh

b. Hydrogen 

chloride (HCl)

2.0E-3 lb/MMBtu or

2.0E-2 lb/MWh

For Method 

26A, 

collect a 

minimum of 

0.75 dscm 

per run; 

for Method 

26, collect 

a minimum 

of 120 

liters per 

run. 

For ASTM 

D6348-033

or Method 

320, sample 

for a 

minimum of 

1 hour.

OR

Sulfur dioxide 

(SO2)

4

2.0E-1 lb/MMBtu or

1.5E0 lb/MWh

SO2 CEMS.

c. Mercury (Hg) 4.0E0 lb/TBtu or

4.0E-2 lb/GWh

LEE Testing 

for 30 days 

with 10 

days 

maximum per 

Method 30B 

run or Hg 

CEMS or 

sorbent 

trap 

monitoring 

system
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 992 of 1103

only.

3. IGCC unit. a. Filterable 

particulate 

matter (PM)

4.0E-2 lb/MMBtu or

4.0E-1 lb/MWh2

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Total non-Hg 

HAP metals

6.0E-5 lb/MMBtu or

5.0E-1 lb/GWh

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

1.4E0 lb/TBtu or

2.0E-2 lb/GWh

1.5E0 lb/TBtu or

2.0E-2 lb/GWh

1.0E-1 lb/TBtu or

1.0E-3 lb/GWh

1.5E-1 lb/TBtu or

2.0E-3 lb/GWh

2.9E0 lb/TBtu or

3.0E-2 lb/GWh

1.2E0 lb/TBtu or

2.0E-2 lb/GWh

1.9E+2 lb/MMBtu or

1.8E0 lb/MWh

2.5E0 lb/TBtu or

3.0E-2 lb/GWh

6.5E0 lb/TBtu or

7.0E-2 lb/GWh

2.2E+1 lb/TBtu or

3.0E-1 lb/GWh

Collect a 

minimum of 

2 dscm per 

run.

b. Hydrogen 

chloride (HCl)

5.0E-4 lb/MMBtu or

5.0E-3 lb/MWh

For Method 

26A, 

collect a 

minimum of 

1 dscm per

run; for 

Method 26, 

collect a 

minimum of 

120 liters 

per run. 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 993 of 1103

For ASTM 

D6348-033

or Method 

320, sample 

for a 

minimum of 

1 hour.

c. Mercury (Hg) 2.5E0 lb/TBtu or

3.0E-2 lb/GWh

LEE Testing 

for 30 days 

with 10 

days 

maximum per 

Method 30B 

run or Hg 

CEMS or 

sorbent 

trap 

monitoring 

system

only.

4. Liquid oilfired unit –

continental

(excluding 

limited-use 

liquid oilfired 

subcategory 

units).

a. Filterable 

particulate 

matter (PM)

3.0E-2 lb/MMBtu or

3.0E-1 lb/MWh2

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Total HAP 

metals

8.0E-4 lb/MMBtu or 

8.0E-3 lb/MWh

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

1.3E+1 lb/TBtu or

2.0E-1 lb/GWh

2.8E0 lb/TBtu or

3.0E-2 lb/GWh

2.0E-1 lb/TBtu or

2.0E-3 lb/GWh

3.0E-1 lb/TBtu or

2.0E-3 lb/GWh

5.5E0 lb/TBtu or

6.0E-2 lb/GWh

Collect a 

minimum of 

1 dscm per 

run.
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 994 of 1103

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

2.1E+1 lb/TBtu or

3.0E-1 lb/GWh

8.1E0 lb/TBtu or

8.0E-2 lb/GWh

2.2E+1 lb/TBtu or

3.0E-1 lb/GWh

1.1E+2 lb/TBtu or

1.1E0 lb/GWh

3.3E0 lb/TBtu or

4.0E-2 lb/GWh

Mercury (Hg) 2.0E-1 lb/TBtu or

2.0E-3 lb/GWh

For Method 

30B sample 

volume 

determinati

on (Section 

8.2.4), the 

estimated 

Hg 

concentrati

on should 

nominally 

be < 1⁄2 the 

standard.

b. Hydrogen 

chloride (HCl)

2.0E-3 lb/MMBtu or

1.0E-2 lb/MWh

For Method 

26A, 

collect a 

minimum of 

1 dscm per

Run; for 

Method 26, 

collect a 

minimum of 

120 liters 

per run. 

For ASTM 

D6348-033

or Method 

320, sample 

for a 

minimum of 

1 hour.

c. Hydrogen 4.0E-4 lb/MMBtu or For Method 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 995 of 1103

fluoride (HF) 4.0E-3 lb/MWh 26A, 

collect a 

minimum of 

1 dscm per

run; for 

Method 26, 

collect a 

minimum of 

120 liters 

per run. 

For ASTM 

D6348-033

or Method 

320, sample 

for a 

minimum of 

1 hour.

5. Liquid oilfired unit –

non-continental

(excluding 

limited-use 

liquid oilfired 

subcategory 

units).

a. Filterable 

particulate 

matter (PM)

3.0E-2 lb/MMBtu or

3.0E-1 lb/MWh2

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Total HAP 

metals

6.0E-4 lb/MMBtu or 

7.0E-3 lb/MWh

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

2.2E0 lb/TBtu or

2.0E-2 lb/GWh

4.3E0 lb/TBtu or

8.0E-2 lb/GWh

6.0E-1 lb/TBtu or

3.0E-3 lb/GWh

3.0E-1 lb/TBtu or

3.0E-3 lb/GWh

3.1E+1 lb/TBtu or

3.0E-1 lb/GWh

1.1E+2 lb/TBtu or

1.4E0 lb/GWh

4.9E0 lb/TBtu or

Collect a 

minimum of 

2 dscm per 

run.
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 996 of 1103

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-2 lb/GWh

2.0E+1 lb/TBtu or

3.0E-1 lb/GWh

4.7E+2 lb/TBtu or

4.1E0 lb/GWh

9.8E0 lb/TBtu or

2.0E-1 lb/GWh

Mercury (Hg) 4.0E-2 lb/TBtu or

4.0E-4 lb/GWh

For Method 

30B sample 

volume 

determinati

on (Section 

8.2.4), the 

estimated 

Hg 

concentrati

on should 

nominally 

be < 1⁄2 the 

standard.

b. Hydrogen 

chloride (HCl)

2.0E-4 lb/MMBtu or

2.0E-3 lb/MWh

For Method 

26A, 

collect a 

minimum of 

1 dscm per

run; for 

Method 26, 

collect a 

minimum of 

120 liters 

per run. 

For ASTM 

D6348-033

or Method 

320, sample 

for a 

minimum of 

2 hours.

c. Hydrogen 

fluoride (HF)

6.0E-5 lb/MMBtu or

5.0E-4 lb/MWh

For Method 

26A, 

collect a 

minimum of 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 997 of 1103

3 dscm per 

run. 

For ASTM 

D6348-033

or Method 

320, sample 

for a 

minimum of 

2 hours.

6. Solid oilderived fuelfired unit.a. Filterable 

particulate 

matter (PM)

8.0E-3 lb/MMBtu or

9.0E-2 lb/MWh2

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Total non-Hg 

HAP metals

4.0E-5 lb/MMBtu or

6.0E-1 lb/GWh

Collect a 

minimum of 

1 dscm per 

run.

OR OR

Individual HAP 

metals

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-1 lb/TBtu or

8.0E-3 lb/GWh

3.0E-1 lb/TBtu or

5.0E-3 lb/GWh

6.0E-2 lb/TBtu or

6.0E-4 lb/GWh

3.0E-1 lb/TBtu or

4.0E-3 lb/GWh

8.0E-1 lb/TBtu or

2.0E-2 lb/GWh

1.1E0 lb/TBtu or

2.0E-2 lb/GWh

8.0E-1 lb/TBtu or

2.0E-2 lb/GWh

2.3E0 lb/TBtu or

4.0E-2 lb/GWh

9.0E0 lb/TBtu or

2.0E-1 lb/GWh

1.2E0 lb/TBtu

2.0E-2 lb/GWh

Collect a 

minimum of 

3 dscm per 

run.

b. Hydrogen 5.0E-3 lb/MMBtu or For Method 
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Page 998 of 1103

chloride (HCl) 8.0E-2 lb/MWh 26A, 

collect a 

minimum of 

0.75 dscm 

per run; 

for Method 

26, collect 

a minimum 

of 120 

liters per 

run. 

For ASTM 

D6348-033

or Method 

320, sample 

for a 

minimum of 

1 hour.

OR

Sulfur dioxide 

(SO2)

4

3.0E-1 lb/MMBtu or

2.0E0 lb/MWh

SO2 CEMS.

c. Mercury (Hg) 2.0E-1 lb/TBtu or

2.0E-3 lb/GWh

LEE Testing 

for 30 days 

with 10 

days 

maximum per 

Method 30B 

run or Hg 

CEMS or 

Sorbent 

trap 

monitoring 

system

only.

1 For LEE emissions testing for total PM, total HAP metals, 

individual HAP metals, HCl, and HF, the required minimum 

sampling volume must be increased nominally by a factor of two.

2 Gross electric output.

3 Incorporated by reference, see §63.14.

4 You may not use the alternate SO2 limit if your EGU does not 

have some form of FGD system and SO2 CEMS installed.

Table 3 to Subpart UUUUU of Part 63 — Work Practice Standards
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Page 999 of 1103

As stated in §§63.9991, you must comply with the following 

applicable work practice standards:

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

1. An existing EGU Conduct a tune-up of the EGU burner 

and combustion controls at least each 

36 calendar months, or each 48 

calendar months if neural network

combustion optimization software is 

employed, as specified in 

§63.10021(e).

2. A new or 

reconstructed EGU

Conduct a tune-up of the EGU burner 

and combustion controls at least each 

36 calendar months, or each 48 

calendar months if neural network

combustion optimization software is 

employed, as specified in 

§63.10021(e).

3. A coal-fired, 

liquid oil-fired, or 

solid oil-derived 

fuel-fired EGU 

during startup

You must operate all CMS during 

startup. Startup means either the 

first-ever firing of fuel in a boiler

for the purpose of producing 

electricity, or the firing of fuel in 

a boiler after a shutdown event for 

any purpose. Startup ends when any of 

the steam from the boiler is used to 

generate electricity for sale over the 

grid or for any other purpose 

(including on site use). For startup 

of a unit, you must use clean fuels, 

either natural gas or distillate oil 

or a combination of clean fuels for 

ignition. Once you convert to firing 

coal, residual oil, or solid oilderived fuel, you must engage all of 

the applicable control technologies 

except dry scrubber and SCR. You must 

start your dry scrubber and SCR 

systems, if present, appropriately to 

comply with relevant standards 

applicable during normal operation.

You must comply with all applicable 

emissions limits at all times except 

for periods that meet the definitions 

of startup and shutdown in this 

subpart. You must keep records during 
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Page 1000 of 1103

periods of startup. You must provide 

reports concerning activities and 

periods of startup, as specified in 

§63.10011(g) and §63.10021(h) and (i).

4. A coal-fired, 

liquid oil-fired, or 

solid oil-derived 

fuel-fired EGU 

during shutdown

You must operate all CMS during 

shutdown. Shutdown means the cessation 

of operation of a boiler for any 

purpose. Shutdown begins either when 

none of the steam from the boiler is 

used to generate electricity for sale 

over the grid or for any other purpose 

(including on-site use) or at the 

point of no fuel being fired in the 

boiler. Shutdown ends when there is 

both no electricity being generated 

and no fuel being fired in the boiler.

During shutdown, you must operate all 

applicable control technologies while 

firing coal, residual oil, or solid

oil-derived fuel. You must comply with 

all applicable emissions limits at all 

times except for periods that meet the 

definitions of startup and shutdown in 

this subpart. You must keep records 

during periods of startup. You must 

provide reports concerning activities 

and periods of startup, as specified 

in §63.10011(g) and §63.10021(h) and 

(i).

Table 4 to Subpart UUUUU of Part 63 — Operating Limits for EGUs

As stated in §63.9991, you must comply with the applicable 

operating limits:

If you 

demonstrate 

compliance using 

...

You must meet these operating limits

1. PM CPMS Maintain the 30-boiler operating day rolling 

average PM CPMS output at or below the highest 1-
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Page 1001 of 1103

hour average measured during the most recent 

performance test demonstrating compliance with 

the filterable PM, total non-mercury HAP metals

(total HAP metals, for liquid oil-fired units), 

or individual non-mercury HAP metals (individual 

HAP metals including Hg, for liquid oil-fired 

units) emissions limitation(s).

Table 5 to Subpart UUUUU of Part 63 — Performance Testing 

Requirements

As stated in §63.10007, you must comply with the following 

requirements for performance testing for existing, new or 

reconstructed affected sources:1

To conduct a 

performance 

test for the 

following 

pollutant ...

Using...

You must perform the 

following activities, 

as applicable to your 

input- or output-based 

emission limit ...

Using ...2

1. Filterable 

Particulate 

matter (PM)

Emissions 

Testing

a. Select sampling 

ports location and the 

number of traverse 

points.

Method 1 at 

Appendix A-1 to 

Part 60 of this 

chapter.

b. Determine velocity 

and volumetric flowrate of the stack gas.

Method 2, 2A, 

2C, 2F, 2G or 

2H at Appendix 

A-1 or A-2 to 

Part 60 of this 

chapter.

c. Determine oxygen 

and carbon dioxide 

concentrations of the 

stack gas.

Method 3A or 3B 

at Appendix A-2 

to Part 60 of 

this chapter, 

or ANSI/ASME 

PTC 19.10-

1981.3

d. Measure the 

moisture content of 

the stack gas.

Method 4 at 

Appendix A-3 to 

Part 60 of this 

chapter. 

e. Measure the Method 5 at 
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Page 1002 of 1103

filterable PM 

concentration.

Appendix A-3 to 

Part 60 of this 

chapter.

For positive 

pressure fabric 

filters, Method 

5D at Appendix 

A-3 to Part 60 

of this chapter 

for filterable 

PM emissions. 

Note that the 

Method 5 front 

half 

temperature 

shall be 160o ± 

14oC (320o ± 

25oF).

f. Convert emissions 

concentration to 

lb/MMBtu or lb/MWh 

emissions rates.

Method 19 Ffactor 

methodology at 

Appendix A-7 to 

Part 60 of this 

chapter, or 

calculate using 

mass emissions 

rate and 

electrical 

output data 

(see 

§63.10007(e)).

OR OR

a. Install, certify, 

operate, and maintain 

the PM CEMS.

Performance 

Specification 

11 at Appendix 

B to Part 60 of 

this chapter 

and Procedure 2 

at Appendix F 

to Part 60 of 

this chapter.
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Page 1003 of 1103

PM CEMS

b. Install, certify, 

operate, and maintain 

the diluent gas, flow 

rate, and/or moisture 

monitoring systems.

Part 75 of this 

chapter and 

§§63.10010 (a), 

(b), (c), and 

(d).

c. Convert hourly 

emissions 

concentrations to 30 

boiler operating day 

rolling average 

lb/MMBtu or lb/MWh 

emissions rates.

Method 19 

F-factor 

methodology at 

Appendix A-7 to 

Part 60 of this 

chapter, or 

calculate using 

mass emissions 

rate and 

electrical 

output data 

(see 

§63.10007(e)).

2. Total or 

individual nonHg HAP metals

Emissions 

Testing

a. Select sampling 

ports location and the 

number of traverse 

points.

Method 1 at 

Appendix A-1 to 

Part 60 of this 

chapter.

b. Determine velocity 

and volumetric flowrate of the stack gas.

Method 2, 2A, 

2C, 2F, 2G or 

2H at Appendix 

A-1 or A-2 to 

Part 60 of this 

chapter.

c. Determine oxygen 

and carbon dioxide 

concentrations of the 

stack gas.

Method 3A or 3B 

at Appendix A-2 

to Part 60 of 

this chapter, 

or ANSI/ASME 

PTC 19.10-

1981.3

d. Measure the 

moisture content of 

the stack gas.

Method 4 at 

Appendix A-3 to 

Part 60 of this 

chapter.

e. Measure the HAP 

metals emissions 

concentrations and 

Method 29 at 

Appendix A-8 to 

Part 60 of this 
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Page 1004 of 1103

determine each 

individual HAP metals 

emissions 

concentration, as well 

as the total 

filterable HAP metals 

emissions 

concentration and 

total HAP metals 

emissions 

concentration.

chapter. For 

liquid oilfired units, Hg 

is included in 

HAP metals and 

you may use 

Method 29, 

Method 30B at 

Appendix A-8 to 

Part 60 of this 

chapter; for 

Method 29, you 

must report the 

front half and 

back half 

results 

separately.

f. Convert emissions 

concentrations 

(individual HAP 

metals, total 

filterable HAP metals, 

and total HAP metals) 

to lb/MMBtu or lb/MWh 

emissions rates.

Method 19 Ffactor 

methodology at 

Appendix A-7 to 

Part 60 of this 

chapter, or 

calculate using 

mass emissions 

rate and 

electrical 

output data 

(see 

§63.10007(e)).

3. Hydrogen 

chloride (HCl) 

and hydrogen 

fluoride (HF)

Emissions 

Testing

a. Select sampling 

ports location and the 

number of traverse 

points.

Method 1 at 

Appendix A-1 to 

Part 60 of this 

chapter.

b. Determine velocity 

and volumetric flowrate of the stack gas.

Method 2, 2A, 

2C, 2F, 2G or 

2H at Appendix 

A-1 or A-2 to 

Part 60 of this 

chapter.

c. Determine oxygen 

and carbon dioxide 

concentrations of the 

Method 3A or 3B 

at Appendix A-2 

to Part 60 of 
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Page 1005 of 1103

stack gas. this chapter, 

or ANSI/ASME 

PTC 19.10-

1981.3

d. Measure the 

moisture content of 

the stack gas.

Method 4 at 

Appendix A-3 to 

Part 60 of this 

chapter.

e. Measure the HCl and 

HF emissions 

concentrations.

Method 26 or 

Method 26A at 

Appendix A-8 to 

Part 60 of this 

chapter or 

Method 320 at 

Appendix A to 

Part 63 of this 

chapter or ASTM 

6348-033 with 

(1) additional 

quality 

assurance 

measures in 

footnote4 and 

(2)spiking 

levels 

nominally no 

greater than 

two times the 

level 

corresponding 

to the 

applicable 

emission limit. 

Method 26A must 

be used if 

there are 

entrained water 

droplets in the 

exhaust stream.
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Page 1006 of 1103

f. Convert emissions 

concentration to 

lb/MMBtu or lb/MWh 

emissions rates.

Method 19 Ffactor 

methodology at 

Appendix A-7 to 

Part 60 of this 

chapter, or 

calculate using 

mass emissions 

rate and 

electrical 

output data 

(see 

§63.10007(e)).

OR OR

HCl and/or 

HF CEMS

a. Install, certify, 

operate, and maintain 

the HCl or HF CEMS.

Appendix B of 

this subpart.

b. Install, certify, 

operate, and maintain 

the diluent gas, flow 

rate, and/or moisture 

monitoring systems.

Part 75 of this 

chapter and 

§§63.10010 (a), 

(b), (c), and 

(d).

c. Convert hourly 

emissions 

concentrations to 30 

boiler operating day 

rolling average 

lb/MMBtu or lb/MWh 

emissions rates.

Method 19 

F-factor 

methodology at 

Appendix A-7 to 

Part 60 of this 

chapter, or 

calculate using 

mass emissions 

rate and 

electrical 

output data 

(see 

§63.10007(e)).

4. Mercury (Hg) Emissions 

Testing

a. Select sampling 

ports location and the 

number of traverse 

points.

Method 1 at 

Appendix A-1 to 

Part 60 of this 

chapter or 

Method 30B at 

Appendix A-8 

for Method 30B 
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Page 1007 of 1103

point 

selection.

b. Determine velocity 

and volumetric flowrate of the stack gas.

Method 2, 2A, 

2C, 2F, 2G or 

2H at Appendix 

A-1 or A-2 to 

Part 60 of this 

chapter. 

c. Determine oxygen 

and carbon dioxide 

concentrations of the 

stack gas.

Method 3A or 3B 

at Appendix A-1 

to Part 60 of 

this chapter, 

or ANSI/ASME 

PTC 19.10-

1981.3

d. Measure the 

moisture content of 

the stack gas.

Method 4 at 

Appendix A-3 to 

Part 60 of this 

chapter.

e. Measure the Hg 

emission 

concentration.

Method 30B at 

Appendix A-8 to 

Part 60 of this 

chapter, ASTM 

D6784, or 

Method 29 at 

Appendix A-8 to 

Part 60 of this 

chapter; for 

Method 29, you 

must report the 

front half and 

back half 

results 

separately.

f. Convert emissions 

concentration to 

lb/TBtu or lb/GWh 

emission rates.

Method 19 Ffactor 

methodology at 

Appendix A-7 to 

Part 60 of this 

chapter, or 

calculate using 

mass emissions 
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Page 1008 of 1103

rate and 

electrical 

output data 

(see 

§63.10007(e)).

OR OR

Hg CEMS

a. Install, certify, 

operate, and maintain 

the CEMS.

Sections 3.2.1 

and 5.1 of 

Appendix A of 

this subpart.

b. Install, certify, 

operate, and maintain 

the diluent gas, flow 

rate, and/or moisture 

monitoring systems.

Part 75 of this 

chapter and 

§§63.10010 (a), 

(b), (c), and 

(d).

c. Convert hourly 

emissions 

concentrations to 30 

boiler operating day 

rolling average 

lb/TBtu or lb/GWh 

emissions rates.

Section 6 of 

Appendix A to 

this subpart.

OR OR

Sorbent 

trap 

monitoring 

system

a. Install, certify, 

operate, and maintain 

the sorbent trap 

monitoring system.

Sections 3.2.2 

and 5.2 of 

Appendix A to 

this subpart.

b. Install, operate, 

and maintain the 

diluent gas, flow 

rate, and/or moisture 

monitoring systems.

Part 75 of this 

chapter and 

§§63.10010 (a), 

(b), (c), and 

(d).

c. Convert emissions 

concentrations to 30 

boiler operating day 

rolling average 

lb/TBtu or lb/GWh 

emissions rates.

Section 6 of 

Appendix A to 

this subpart.

OR OR
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Page 1009 of 1103

LEE 

testing

a. Select sampling 

ports location and the 

number of traverse 

points.

Single point 

located at the 

10% centroidal 

area of the 

duct at a port 

location per 

Method 1 at

Appendix A-1 to 

Part 60 of this 

chapter or 

Method 30B at 

Appendix A-8 

for Method 30B 

point 

selection.

b. Determine velocity 

and volumetric flowrate of the stack gas.

Method 2, 2A, 

2C, 2F, 2G, or 

2H at Appendix 

A-1 or A-2 to 

Part 60 of this 

chapter or flow 

monitoring 

system 

certified per 

Appendix A of 

this subpart.

c. Determine oxygen 

and carbon dioxide 

concentrations of the 

stack gas.

Method 3A or 3B 

at Appendix A-1 

to Part 60 of 

this chapter, 

or ANSI/ASME 

PTC 19.10-

1981,3 or 

diluent gas 

monitoring 

systems 

certified 

according to 

Part 75 of this 

chapter.

d. Measure the 

Method 4 at 

Appendix A-3 to 

Part 60 of this 

chapter, or 
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Page 1010 of 1103

moisture content of 

the stack gas.

moisture 

monitoring 

systems 

certified 

according to 

Part 75 of this 

chapter.

e. Measure the Hg 

emission 

concentration.

Method 30B at 

Appendix A-8 to 

Part 60 of this 

chapter; 

perform a 30 

operating day 

test, with a 

maximum of 10 

operating days 

per run (i.e., 

per pair of 

sorbent traps) 

or sorbent trap 

monitoring 

system or Hg 

CEMS certified 

per Appendix A 

of this 

subpart.

f. Convert emissions 

concentrations from 

the LEE test to 

lb/TBtu or lb/GWh 

emissions rates.

Method 19 Ffactor 

methodology at 

Appendix A-7 to 

Part 60 of this 

chapter, or 

calculate using 

mass emissions 

rate and 

electrical 

output data 

(see 

§63.10007(e)).

g. Convert average 

lb/TBtu or lb/GWh Hg 

emission rate to 

lb/year, if you are 

attempting to meet the 

Potential 

maximum annual 

heat input in 

TBtu or 

potential 
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Page 1011 of 1103

22.0 lb/year 

threshold.

maximum 

electricity 

generated in 

GWh.

5. Sulfur 

dioxide (SO2)

SO2 CEMS a. Install, certify, 

operate, and maintain 

the CEMS.

Part 75 of this 

chapter and 

§§63.10010 (a) 

and (f).

b. Install, operate, 

and maintain the 

diluent gas, flow 

rate, and/or moisture 

monitoring systems.

Part 75 of this 

chapter and 

§§63.10010 (a), 

(b), (c), and 

(d).

c. Convert hourly 

emissions 

concentrations to 30 

boiler operating day 

rolling average 

lb/MMBtu or lb/MWh 

emissions rates.

Method 19 Ffactor 

methodology at 

Appendix A-7 to 

Part 60 of this 

chapter, or 

calculate using 

mass emissions 

rate and 

electrical 

output data 

(see 

§63.10007(e)).

1 Regarding emissions data collected during periods of startup or 

shutdown, see §§63.10020(b) and (c) and §63.10021(h).

2 See Tables 1 and 2 to this subpart for required sample volumes 

and/or sampling run times.

3 Incorporated by reference, see §63.14.

4 When using ASTM D6348-03, the following conditions must be met:

(1) The test plan preparation and implementation in the Annexes

to ASTM D6348-03, Sections A1 through A8 are mandatory; (2) For 

ASTM D6348-03 Annex A5 (Analyte Spiking Technique), the percent 

(%) R must be determined for each target analyte (see Equation 

A5.5); (3) For the ASTM D6348-03 test data to be acceptable for 

a target analyte, %R must be 70 % ≥ R ≤ 130%; and (4) The %R 

value for each compound must be reported in the test report and 

all field measurements corrected with the calculated %R value 

for that compound using the following equation:

 

% R x 100

M e a s u r e d C o n c e n tr a tio n in S ta c k

R e p o r te d R e s u lt

 
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Page 1012 of 1103

Table 6 to Subpart UUUUU of Part 63 — Establishing PM CPMS 

Operating Limits

As stated in §63.10007, you must comply with the following 

requirements for establishing operating limits:

If you have 

an 

applicable 

emission 

limit for 

...

And you choose 

to establish PM 

CPMS operating 

limits, you 

must...

And... Using... According to 

the following 

procedures...

Particulate 

matter 

(PM), total 

non-mercury

HAP metals, 

individual 

non-mercury

HAP metals, 

total HAP 

metals, 

individual 

HAP metals

Install, 

certify, 

maintain, and 

operate a PM 

CPMS for 

monitoring 

emissions 

discharged to 

the atmosphere 

according to 

§63.10010(g)(1)

Establish 

a sitespecific 

operating 

limit in 

units of 

PM CPMS 

output 

signal 

(e.g., 

milliamps, 

mg/acm, or 

other raw 

signal)

Data from 

the PM CPMS 

and the PM 

or HAP 

metals 

performance 

tests

1. Collect PM 

CPMS output 

data during 

the entire 

period of the 

performance 

tests.

2. Record the 

average 

hourly PM 

CPMS output

for each test 

run in the 

three run 

performance 

test.

3. Determine 

the highest 

1-hour 

average PM 

CPMS measured 

during the 

performance 

test 

demonstrating 

compliance 

with the 

filterable PM 

or HAP metals 

emissions 
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Page 1013 of 1103

limitations.

Table 7 to Subpart UUUUU of Part 63 — Demonstrating Continuous 

Compliance

As stated in §63.10021, you must show continuous compliance with 

the emission limitations for affected sources according to the 

following:

If you use one of the 

following to meet applicable 

emissions limits, operating 

limits, or work practice 

standards ...

You demonstrate continuous 

compliance by ...

1. CEMS to measure 

filterable PM, SO2, HCl, HF, 

or Hg emissions, or using a 

sorbent trap monitoring 

system to measure Hg

Calculating the 30-boiler operating 

day rolling arithmetic average 

emissions rate in units of the 

applicable emissions standard basis 

at the end of each boiler operating 

day using all of the quality 

assured hourly average CEMS or 

sorbent trap data for the previous 

30 boiler operating days, excluding 

data recorded during periods of 

startup or shutdown.

2. PM CPMS to measure 

compliance with a parametric 

operating limit

Calculating the arithmetic 30-

boiler operating day rolling 

average of all of the quality 

assured hourly average PM CPMS 

output data (e.g., milliamps, PM 

concentration, raw data signal) 

collected for all operating hours 

for the previous 30 boiler 

operating days, excluding data 

recorded during periods of startup 

or shutdown.

3. Site-specific monitoring 

for liquid oil-fired units 

for HCl and HF emission 

limit monitoring

If applicable, by conducting the 

monitoring in accordance with an 

approved site-specific monitoring 

plan.

4. Quarterly performance 

testing for coal-fired, 

solid oil derived fired, or 

liquid oil-fired units to 

measure compliance with one 

Calculating the results of the 

testing in units of the applicable 

emissions standard.
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 1014 of 1103

or more applicable emissions 

limit in Table 1 or 2

5. Conducting periodic 

performance tune-ups of your 

EGU(s) 

Conducting periodic performance 

tune-ups of your EGU(s), as 

specified in §63.10021(e).

6. Work practice standards 

for coal-fired, liquid oilfired, or solid oil-derived 

fuel-fired EGUs during 

startup 

Operating in accordance with Table 

3.

7. Work practice standards 

for coal-fired, liquid oilfired, or solid oil-derived 

fuel-fired EGUs during 

shutdown

Operating in accordance with Table 

3.

Table 8 to Subpart UUUUU of Part 63 — Reporting Requirements

As stated in §63.10031, you must comply with the following 

requirements for reports:

You must 

submit a

The report must contain ... You must submit 

the report ...

1. 

Compliance 

report

a. Information required in 

§63.10031(c)(1) through (4); and

Semiannually 

according to the 

requirements in 

§63.10031(b).

b. If there are no deviations from 

any emission limitation (emission 

limit and operating limit) that 

applies to you and there are no 

deviations from the requirements 

for work practice standards in 

Table 3 to this subpart that apply 

to you, a statement that there 

were no deviations from the 

emission limitations and work 

practice standards during the 

reporting period. If there were no 

periods during which the CMSs, 

including continuous emissions 

monitoring system, and operating 

parameter monitoring systems, were 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 1015 of 1103

out-of-control as specified in 

§63.8(c)(7), a statement that 

there were no periods during which 

the CMSs were out-of-control 

during the reporting period; and

c. If you have a deviation from 

any emission limitation (emission 

limit and operating limit) or work 

practice standard during the 

reporting period, the report must 

contain the information in 

§63.10031(d). If there were 

periods during which the CMSs, 

including continuous emissions 

monitoring systems and continuous

parameter monitoring systems, were 

out-of-control, as specified in 

§63.8(c)(7), the report must 

contain the information in 

§63.10031(e).

Table 9 to Subpart UUUUU of Part 63 — Applicability of General 

Provisions to Subpart UUUUU

As stated in §63.10040, you must comply with the applicable 

General Provisions according to the following:

Citation Subject Applies to subpart UUUUU

§63.1 Applicability Yes.

§63.2 Definitions Yes. Additional terms 

defined in §63.10042.

§63.3 Units and 

Abbreviations

Yes.

§63.4 Prohibited 

Activities and 

Circumvention

Yes.

§63.5 Preconstruction 

Review and 

Notification 

Requirements

Yes.
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§63.6(a), (b)(1)-

(b)(5), (b)(7), 

(c), (f)(2)-(3), 

(g), (h)(2)-

(h)(9), (i), (j)

Compliance with 

Standards and 

Maintenance 

Requirements

Yes.

§63.6(e)(1)(i) General Duty to 

minimize emissions

No. See §63.10000(b) for 

general duty requirement.

§63.6(e)(1)(ii) Requirement to 

correct 

malfunctions ASAP

No.

§63.6(e)(3) SSM Plan 

requirements

No.

§63.6(f)(1) SSM exemption No.

§63.6(h)(1) SSM exemption No.

§63.7(a), (b), 

(c), (d), (e)(2)-

(e)(9), (f), (g), 

and (h)

Performance 

Testing 

Requirements

Yes.

§63.7(e)(1) Performance 

testing

No. See §63.10007.

§63.8 Monitoring 

Requirements

Yes.

63.8(c)(1)(i) General duty to 

minimize emissions 

and CMS operation

No. See §63.10000(b) for 

general duty requirement.

§63.8(c)(1)(iii) Requirement to 

develop SSM Plan 

for CMS

No.

§63.8(d)(3) Written procedures 

for CMS

Yes, except for last 

sentence, which refers to 

an SSM plan. SSM plans 

are not required.

§63.9 Notification 

Requirements

Yes.

§63.10(a), 

(b)(1), (c), 

(d)(1)-(2), (e), 

and (f)

Recordkeeping and 

Reporting 

Requirements

Yes, except for the 

requirements to submit 

written reports under 

§63.10(e)(3)(v).

§63.10(b)(2)(i) Recordkeeping of 

occurrence and 

duration of 

startups and 

shutdowns

No.
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§63.10(b)(2)(ii) Recordkeeping of 

malfunctions

No. See 63.10001 for 

recordkeeping of (1) 

occurrence and duration 

and (2) actions taken 

during malfunction.

§63.10(b)(2)(iii) Maintenance 

records

Yes.

§63.10(b)(2)(iv) Actions taken to 

minimize emissions 

during SSM

No.

§63.10(b)(2)(v) Actions taken to 

minimize emissions 

during SSM

No.

§63.10(b)(2)(vi) Recordkeeping for 

CMS malfunctions

Yes.

§63.10(b)(2)(vii)

-(ix)

Other CMS 

requirements

Yes.

§63.10(b)(3),and 

(d)(3)-(5)

No.

§63.10(c)(7) Additional 

recordkeeping 

requirements for 

CMS – identifying 

exceedances and 

excess emissions

Yes.

§63.10(c)(8) Additional 

recordkeeping 

requirements for 

CMS – identifying 

exceedances and 

excess emissions

Yes.

§63.10(c)(10) Recording nature 

and cause of 

malfunctions

No. See 63.10032(g) and 

(h) for malfunctions 

recordkeeping 

requirements.

§63.10(c)(11) Recording

corrective actions

No. See 63.10032(g) and 

(h) for malfunctions 

recordkeeping 

requirements.

§63.10(c)(15) Use of SSM Plan No.

§63.10(d)(5) SSM reports No. See 63.10021(h) and 

(i) for malfunction 

reporting requirements.

§63.11 Control Device 

Requirements

No.
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§63.12 State Authority 

and Delegation

Yes.

§63.13-63.16 Addresses, 

Incorporation by 

Reference, 

Availability of 

Information, 

Performance Track 

Provisions

Yes.

§63.1(a)(5),(a)(7

)-(a)(9), (b)(2), 

(c)(3)-(4), (d), 

63.6(b)(6), 

(c)(3), (c)(4), 

(d), (e)(2), 

(e)(3)(ii), 

(h)(3), 

(h)(5)(iv), 

63.8(a)(3), 

63.9(b)(3), 

(h)(4), 

63.10(c)(2)-(4), 

(c)(9).

Reserved No.
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Appendix A to Subpart UUUUU—Hg Monitoring Provisions

1. General Provisions

1.1 Applicability. These monitoring provisions apply to the 

measurement of total vapor phase mercury (Hg) in emissions from 

electric utility steam generating units, using either a mercury 

continuous emission monitoring system (Hg CEMS) or a sorbent 

trap monitoring system. The Hg CEMS or sorbent trap monitoring 

system must be capable of measuring the total vapor phase 

mercury in units of the applicable emissions standard (e.g., 

lb/TBtu or lb/GWh), regardless of speciation. 

1.2 Initial Certification and Recertification Procedures. The 

owner or operator of an affected unit that uses a Hg CEMS or a 

sorbent trap monitoring system together with other necessary 

monitoring components to account for Hg emissions in units of 

the applicable emissions standard shall comply with the initial 

certification and recertification procedures in section 4 of 

this appendix.

1.3 Quality Assurance and Quality Control Requirements. The 

owner or operator of an affected unit that uses a Hg CEMS or a 

sorbent trap monitoring system together with other necessary 

monitoring components to account for Hg emissions in units of 

the applicable emissions standard shall meet the applicable 

quality assurance requirements in section 5 of this appendix.
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1.4 Missing Data Procedures. The owner or operator of an 

affected unit is not required to substitute for missing data 

from Hg CEMS or sorbent trap monitoring systems. Any process 

operating hour for which quality-assured Hg concentration data 

are not obtained is counted as an hour of monitoring system 

downtime.

2. Monitoring of Hg Emissions 

2.1 Monitoring System Installation Requirements. Flue gases from 

the affected units under this subpart vent to the atmosphere 

through a variety of exhaust configurations including single 

stacks, common stack configurations, and multiple stack 

configurations. For each of these configurations, §63.10010(a) 

specifies the appropriate location(s) at which to install 

continuous monitoring systems (CMS). These CMS installation 

provisions apply to the Hg CEMS, sorbent trap monitoring 

systems, and other continuous monitoring systems that provide 

data for the Hg emissions calculations in section 6.2 of this 

appendix. 

2.2 Primary and Backup Monitoring Systems. In the electronic 

monitoring plan described in section 7.1.1.2.1 of this appendix, 

you must designate a primary Hg CEMS or sorbent trap monitoring 

system. The primary system must be used to report hourly Hg 

concentration values when the system is able to provide quality-
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Page 1021 of 1103

assured data, i.e., when the system is “in control”. However, to 

increase data availability in the event of a primary monitoring 

system outage, you may install, operate, maintain, and calibrate 

backup monitoring systems, as follows:

2.2.1 Redundant Backup Systems. A redundant backup monitoring 

system may be either a separate Hg CEMS with its own probe, 

sample interface, and analyzer, or a separate sorbent trap 

monitoring system. A redundant backup system is one that is 

permanently installed at the unit or stack location, and is kept 

on “hot standby” in case the primary monitoring system is unable 

to provide quality-assured data. A redundant backup system must 

be represented as a unique monitoring system in the electronic 

monitoring plan. Each redundant backup monitoring system must be 

certified according to the applicable provisions in section 4 of 

this appendix and must meet the applicable on-going QA 

requirements in section 5 of this appendix. 

2.2.2 Non-redundant Backup Monitoring Systems. A non-redundant 

backup monitoring system is a separate Hg CEMS or sorbent trap 

system that has been certified at a particular unit or stack 

location, but is not permanently installed at that location. 

Rather, the system is kept on “cold standby” and may be 

reinstalled in the event of a primary monitoring system outage. 

A non-redundant backup monitoring system must be represented as 
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a unique monitoring system in the electronic monitoring plan. 

Non-redundant backup Hg CEMS must complete the same 

certification tests as the primary monitoring system, with one 

exception. The 7-day calibration error test is not required for 

a non-redundant backup Hg CEMS. Except as otherwise provided in 

section 2.2.4.5 of this appendix, a non-redundant backup 

monitoring system may only be used for 720 hours per year at a 

particular unit or stack location. 

2.2.3 Temporary Like-kind Replacement Analyzers. When a primary 

Hg analyzer needs repair or maintenance, you may temporarily 

install a like-kind replacement analyzer, to minimize data loss. 

Except as otherwise provided in section 2.2.4.5 of this 

appendix, a temporary like-kind replacement analyzer may only be 

used for 720 hours per year at a particular unit or stack 

location. The analyzer must be represented as a component of the

primary Hg CEMS, and must be assigned a 3-character component ID 

number, beginning with the prefix “LK”. 

2.2.4 Quality Assurance Requirements for Non-redundant Backup 

Monitoring Systems and Temporary Like-kind Replacement 

Analyzers. To quality-assure the data from non-redundant backup 

Hg monitoring systems and temporary 

like-kind replacement Hg analyzers, the following provisions 

apply:
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2.2.4.1 When a certified non-redundant backup sorbent trap 

monitoring system is brought into service, you must follow the 

procedures for routine day-to-day operation of the system, in 

accordance with Performance Specification (PS) 12B in appendix B 

to Part 60 of this chapter.

2.2.4.2 When a certified non-redundant backup Hg CEMS or a 

temporary like-kind replacement Hg analyzer is brought into 

service, a calibration error test and a linearity check must be 

performed and passed. A single point system integrity check is 

also required, unless a NIST-traceable source of oxidized Hg was 

used for the calibration error test. 

2.2.4.3 Each non-redundant backup Hg CEMS or temporary like-kind 

replacement Hg analyzer shall comply with all required daily, 

weekly, and quarterly quality-assurance test requirements in 

section 5 of this appendix, for as long as the system or 

analyzer remains in service. 

2.2.4.4 For the routine, on-going quality-assurance of a nonredundant backup Hg monitoring system, a relative accuracy test 

audit (RATA) must be performed and passed at least once every 8 

calendar quarters at the unit or stack location(s) where the 

system will be used. 

2.2.4.5 To use a non-redundant backup Hg monitoring system or a 

temporary like-kind replacement analyzer for more than 720 hours 
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per year at a particular unit or stack location, a RATA must 

first be performed and passed at that location. 

3. Mercury Emissions Measurement Methods

The following definitions, equipment specifications, procedures, 

and performance criteria are applicable to the measurement of 

vapor-phase Hg emissions from electric utility steam generating 

units, under relatively low-dust conditions (i.e., sampling in 

the stack or duct after all pollution control devices). The 

analyte measured by these procedures and specifications is total 

vapor-phase Hg in the flue gas, which represents the sum of 

elemental Hg (Hg0, CAS Number 7439-97-6) and oxidized forms of 

Hg.

3.1 Definitions.

3.1.1 Mercury Continuous Emission Monitoring System or Hg CEMS 

means all of the equipment used to continuously determine the 

total vapor phase Hg concentration. The measurement system may 

include the following major subsystems: sample acquisition, Hg+2

to Hg0 converter, sample transport, sample conditioning, flow 

control/gas manifold, gas analyzer, and data acquisition and 

handling system (DAHS). Hg CEMS may be nominally real-time or 

time-integrated, batch sampling systems that sample the gas on 

an intermittent basis and concentrate on a collection medium 

before intermittent analysis and reporting.
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3.1.2 Sorbent Trap Monitoring System means the equipment

required to monitor Hg emissions continuously by using paired 

sorbent traps containing iodated charcoal (IC) or other suitable 

sorbent medium. The monitoring system consists of a probe, 

paired sorbent traps, an umbilical line, moisture removal 

components, an airtight sample pump, a gas flow meter, and an 

automated data acquisition and handling system. The system 

samples the stack gas at a constant proportional rate relative 

to the stack gas volumetric flow rate. The sampling is a batch 

process. The average Hg concentration in the stack gas for the 

sampling period is determined, in units of micrograms per dry 

standard cubic meter (μg/dscm), based on the sample volume 

measured by the gas flow meter and the mass of Hg collected in 

the sorbent traps.

3.1.3 NIST means the National Institute of Standards and 

Technology, located in Gaithersburg, Maryland.

3.1.4 NIST-Traceable Elemental Hg Standards means either: 

compressed gas cylinders having known concentrations of 

elemental Hg, which have been prepared according to the “EPA 

Traceability Protocol for Assay and Certification of Gaseous 

Calibration Standards”; or calibration gases having known 

concentrations of elemental Hg, produced by a generator that 

meets the performance requirements of the “EPA Traceability 
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Protocol for Qualification and Certification of Elemental 

Mercury Gas Generators” or an interim version of that protocol.

3.1.5 NIST-Traceable Source of Oxidized Hg means a generator 

that is capable of providing known concentrations of vapor phase 

mercuric chloride (HgCl2), and that meets the performance 

requirements of the “EPA Traceability Protocol for Qualification 

and Certification of Mercuric Chloride Gas Generators” or an 

interim version of that protocol.

3.1.6 Calibration Gas means a NIST-traceable gas standard 

containing a known concentration of elemental or oxidized Hg 

that is produced and certified in accordance with an EPA 

traceability protocol.

3.1.7 Span Value means a conservatively high estimate of the Hg 

concentrations to be measured by a CEMS. The span value of a Hg 

CEMS should be set to approximately twice the concentration 

corresponding to the emission standard, rounded off as 

appropriate (see section 3.2.1.4.2 of this appendix).

3.1.8 Zero-Level Gas means calibration gas containing a Hg 

concentration that is below the level detectable by the Hg gas 

analyzer in use.

3.1.9 Low-Level Gas means calibration gas with a concentration 

that is 20 to 30 percent of the span value.

3.1.10 Mid-Level Gas means calibration gas with a concentration 
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that is 50 to 60 percent of the span value.

3.1.11 High-Level Gas means calibration gas with a concentration 

that is 80 to 100 percent of the span value.

3.1.12 Calibration Error Test means a test designed to assess 

the ability of a Hg CEMS to measure the concentrations of 

calibration gases accurately. A zero-level gas and an upscale 

gas are required for this test. For the upscale gas, either a 

mid-level gas or a high-level gas may be used, and the gas may 

either be an elemental or oxidized Hg standard.

3.1.13 Linearity Check means a test designed to determine 

whether the response of a Hg analyzer is linear across its 

measurement range. Three elemental Hg calibration gas standards 

(i.e., low, mid, and high-level gases) are required for this 

test. 

3.1.14 System Integrity Check means a test designed to assess

the transport and measurement of oxidized Hg by a Hg CEMS. 

Oxidized Hg standards are used for this test. For a three-level 

system integrity check, low, mid, and high-level calibration 

gases are required. For a single-level check, either a mid-level 

gas or a high-level gas may be used.

3.1.15 Cycle Time Test means a test designed to measure the 

amount of time it takes for a Hg CEMS, while operating normally, 

to respond to a known step change in gas concentration. For this 
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test, a zero gas and a high-level gas are required. The highlevel gas may be either an elemental or an oxidized Hg standard.

3.1.16 Relative Accuracy Test Audit or RATA means a series of 

nine or more test runs, directly comparing readings from a Hg 

CEMS or sorbent trap monitoring system to measurements made with 

a reference stack test method. The relative accuracy (RA) of the 

monitoring system is expressed as the absolute mean difference 

between the monitoring system and reference method measurements 

plus the absolute value of the 2.5 percent error confidence 

coefficient, divided by the mean value of the reference method 

measurements.

3.1.17 Unit Operating Hour means a clock hour in which a unit 

combusts any fuel, either for part of the hour or for the entire 

hour.

3.1.18 Stack Operating Hour means a clock hour in which gases 

flow through a particular monitored stack or duct (either for 

part of the hour or for the entire hour), while the associated 

unit(s) are combusting fuel.

3.1.19 Operating Day means a calendar day in which a source 

combusts any fuel.

3.1.20 Quality Assurance (QA) Operating Quarter means a calendar 

quarter in which there are at least 168 unit or stack operating 

hours (as defined in this section).
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3.1.21 Grace Period means a specified number of unit or stack 

operating hours after the deadline for a required qualityassurance test of a continuous monitor has passed, in which the 

test may be performed and passed without loss of data.

3.2 Continuous Monitoring Methods.

3.2.1 Hg CEMS. A typical Hg CEMS is shown in Figure A-1. The

CEMS in Figure A-1 is a dilution extractive system, which 

measures Hg concentration on a wet basis, and is the most 

commonly-used type of Hg CEMS. Other system designs may be used, 

provided that the CEMS meets the performance specifications in 

section 4.1.1 of this appendix.

FIGURE A-1. TYPICAL MERCURY CEMS

3.2.1.1 Equipment Specifications.

3.2.1.1.1 Materials of Construction. All wetted sampling system 

Probe

Mercury 

Analyzer

Sample 

Conversion & 

Conditioning

Calibration 

Module 

Dilution 

Air
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components, including probe components prior to the point at 

which the calibration gas is introduced, must be chemically 

inert to all Hg species. Materials such as perfluoroalkoxy (PFA) 

TeflonTM, quartz, and treated stainless steel (SS) are examples 

of such materials.

3.2.1.1.2 Temperature Considerations. All system components 

prior to the Hg+2 to Hg0 converter must be maintained at a sample 

temperature above the acid gas dew point.

3.2.1.1.3 Measurement System Components.

3.2.1.1.3.1 Sample Probe. The probe must be made of the 

appropriate materials as noted in paragraph 3.2.1.1.1 of this 

section, heated when necessary, as described in paragraph 

3.2.1.1.3.4 of this section, and configured with ports for 

introduction of calibration gases.

3.2.1.1.3.2 Filter or Other Particulate Removal Device. The 

filter or other particulate removal device is part of the 

measurement system, must be made of appropriate materials, as 

noted in paragraph 3.2.1.1.1 of this section, and must be 

included in all system tests.

3.2.1.1.3.3 Sample Line. The sample line that connects the probe 

to the converter, conditioning system, and analyzer must be made 

of appropriate materials, as noted in paragraph 3.2.1.1.1 of 

this section.
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3.2.1.1.3.4 Conditioning Equipment. For wet basis systems, such 

as the one shown in Figure A-1, the sample must be kept above 

its dew point either by: heating the sample line and all sample 

transport components up to the inlet of the analyzer (and, for 

hot-wet extractive systems, also heating the analyzer); or 

diluting the sample prior to analysis using a dilution probe 

system. The components required for these operations are 

considered to be conditioning equipment. For dry basis 

measurements, a condenser, dryer or other suitable device is 

required to remove moisture continuously from the sample gas, 

and any equipment needed to heat the probe or sample line to 

avoid condensation prior to the moisture removal component is 

also required.

3.2.1.1.3.5 Sampling Pump. A pump is needed to push or pull the 

sample gas through the system at a flow rate sufficient to 

minimize the response time of the measurement system. If a 

mechanical sample pump is used and its surfaces are in contact 

with the sample gas prior to detection, the pump must be leak 

free and must be constructed of a material that is non-reactive 

to the gas being sampled (see paragraph 3.2.1.1.1 of this 

section). For dilution-type measurement systems, such as the 

system shown in Figure A-1, an ejector pump (eductor) may be 

used to create a sufficient vacuum that sample gas will be drawn 
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through a critical orifice at a constant rate. The ejector pump 

must be constructed of any material that is non-reactive to the 

gas being sampled.

3.2.1.1.3.6 Calibration Gas System(s). Design and equip each Hg 

CEMS to permit the introduction of known concentrations of 

elemental Hg and HgCl2 separately, at a point preceding the 

sample extraction filtration system, such that the entire 

measurement system can be checked. The calibration gas system(s) 

must be designed so that the flow rate exceeds the sampling 

system flow requirements and that the gas is delivered to the 

CEMS at atmospheric pressure.

3.2.1.1.3.7 Sample Gas Delivery. The sample line may feed 

directly to either a converter, a by-pass valve (for Hg 

speciating systems), or a sample manifold. All valve and/or 

manifold components must be made of material that is nonreactive to the gas sampled and the calibration gas, and must be 

configured to safely discharge any excess gas.

3.2.1.1.3.8 Hg Analyzer. An instrument is required that 

continuously measures the total vapor phase Hg concentration in 

the gas stream. The analyzer may also be capable of measuring 

elemental and oxidized Hg separately.

3.2.1.1.3.9 Data Recorder. A recorder, such as a computerized 

data acquisition and handling system (DAHS), digital recorder, 
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or data logger, is required for recording measurement data.

3.2.1.2 Reagents and Standards.

3.2.1.2.1 NIST Traceability. Only NIST-certified or NISTtraceable calibration gas standards and reagents (as defined in 

paragraphs 3.1.4 and 3.1.5 of this section) shall be used for 

the tests and procedures required under this subpart. 

Calibration gases with known concentrations of Hg0 and HgCl2 are 

required. Special reagents and equipment may be needed to 

prepare the Hg0 and HgCl2 gas standards (e.g., NIST-traceable 

solutions of HgCl2 and gas generators equipped with mass flow 

controllers).

3.2.1.2.2 Required Calibration Gas Concentrations.

3.2.1.2.2.1 Zero-Level Gas. A zero-level calibration gas with a 

Hg concentration below the level detectable by the Hg analyzer 

is required for calibration error tests and cycle time tests of 

the CEMS.

3.2.1.2.2.2 Low-Level Gas. A low-level calibration gas with a Hg 

concentration of 20 to 30 percent of the span value is required 

for linearity checks and 3-level system integrity checks of the 

CEMS. Elemental Hg standards are required for the linearity 

checks and oxidized Hg standards are required for the system 

integrity checks.

3.2.1.2.2.3 Mid-Level Gas. A mid-level calibration gas with a Hg 
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concentration of 50 to 60 percent of the span value is required 

for linearity checks and for 3-level system integrity checks of 

the CEMS, and is optional for calibration error tests and 

single-level system integrity checks. Elemental Hg standards are 

required for the linearity checks, oxidized Hg standards are 

required for the system integrity checks, and either elemental 

or oxidized Hg standards may be used for the calibration error 

tests.

3.2.1.2.2.4 High-Level Gas. A high-level calibration gas with a 

Hg concentration of 80 to 100 percent of the span value is 

required for linearity checks, 3-level system integrity checks, 

and cycle time tests of the CEMS, and is optional for 

calibration error tests and single-level system integrity 

checks. Elemental Hg standards are required for the linearity 

checks, oxidized Hg standards are required for the system 

integrity checks, and either elemental or oxidized Hg standards 

may be used for the calibration error and cycle time tests.

3.2.1.3 Installation and Measurement Location. For the Hg CEMS 

and any additional monitoring system(s) needed to convert Hg 

concentrations to the desired units of measure (i.e., a flow 

monitor, CO2 or O2 monitor, and/or moisture monitor, as 

applicable), install each monitoring system at a location: that 

is consistent with 63.10010(a); that represents the emissions 
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exiting to the atmosphere; and where it is likely that the CEMS 

can pass the relative accuracy test.

3.2.1.4 Monitor Span and Range Requirements. Determine the 

appropriate span and range value(s) for the Hg CEMS as described 

in paragraphs 3.2.1.4.1 through 3.2.1.4.3 of this section.

3.2.1.4.1 Maximum Potential Concentration. There are three 

options for determining the maximum potential Hg concentration 

(MPC). Option 1 applies to coal combustion. You may use a 

default value of 10 μg/scm for all coal ranks (including coal 

refuse) except for lignite; for lignite, use 16 μg/scm. If 

different coals are blended as part of normal operation, use the 

highest MPC for any fuel in the blend. Option 2 is to base the 

MPC on the results of site-specific Hg emission testing. This 

option may be used only if the unit does not have add-on Hg 

emission controls or a flue gas desulfurization system, or if 

testing is performed upstream of all emission control devices. 

If Option 2 is selected, perform at least three test runs at the 

normal operating load, and the highest Hg concentration obtained 

in any of the tests shall be the MPC. Option 3 is to use fuel 

sampling and analysis to estimate the MPC. To make this 

estimate, use the average Hg content (i.e., the weight 

percentage) from at least three representative fuel samples, 

together with other available information, including, but not 
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limited to the maximum fuel feed rate, the heating value of the 

fuel, and an appropriate F-factor. Assume that all of the Hg in 

the fuel is emitted to the atmosphere as vapor-phase Hg. 

3.2.1.4.2 Span Value. To determine the span value of the Hg 

CEMS, multiply the Hg concentration corresponding to the 

applicable emissions standard by two. If the result of this 

calculation is an exact multiple of 10 μg/scm, use the result as 

the span value. Otherwise, round off the result to either: the 

next highest integer; the next highest multiple of 5 μg/scm; or

the next highest multiple of 10 μg/scm.

3.2.1.4.3 Analyzer Range. The Hg analyzer must be capable of 

reading Hg concentration as high as the MPC.

3.2.2 Sorbent Trap Monitoring System. A sorbent trap monitoring 

system (as defined in paragraph 3.1.2 of this section) may be 

used as an alternative to a Hg CEMS. If this option is selected, 

the monitoring system shall be installed, maintained, and 

operated in accordance with Performance Specification (PS) 12B 

in Appendix B to Part 60 of this chapter. The system shall be 

certified in accordance with the provisions of section 4.1.2 of 

this appendix.

3.2.3 Other Necessary Data Collection. To convert measured 

hourly Hg concentrations to the units of the applicable 

emissions standard (i.e., lb/TBtu or lb/GWh), additional data 
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must be collected, as described in paragraphs 3.2.3.1 through

3.2.3.3 of this section. Any additional monitoring systems 

needed for this purpose must be certified, operated, maintained, 

and quality-assured according to the applicable provisions of 

Part 75 of this chapter (see §§63.10010(b) through (d)). The 

calculation methods for the types of emission limits described 

in paragraphs 3.2.3.1 and 3.2.3.2 of this section are presented 

in section 6.2 of this appendix.

3.2.3.1 Heat Input-Based Emission Limits. For a heat input-based 

Hg emission limit (i.e., in lb/TBtu), data from a certified CO2

or O2 monitor are needed, along with a fuel-specific F-factor and 

a conversion constant to convert measured Hg concentration 

values to the units of the standard. In some cases, the stack 

gas moisture content must also be considered in making these 

conversions.

3.2.3.2 Electrical Output-Based Emission Rates. If the 

applicable Hg limit is electrical output-based (i.e., lb/GWh), 

hourly electrical load data and unit operating times are 

required in addition to hourly data from a certified stack gas 

flow rate monitor and (if applicable) moisture data.

3.2.3.3 Sorbent Trap Monitoring System Operation. Routine 

operation of a sorbent trap monitoring system requires the use 

of a certified stack gas flow rate monitor, to maintain an 
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established ratio of stack gas flow rate to sample flow rate.

4. Certification and Recertification Requirements

4.1 Certification Requirements. All Hg CEMS and sorbent trap 

monitoring systems and the additional monitoring systems used to 

continuously measure Hg emissions in units of the applicable 

emissions standard in accordance with this appendix must be 

certified in a timely manner, such that the initial compliance 

demonstration is completed no later than the applicable date in 

§63.10005(g).

4.1.1 Hg CEMS. Table A-1, below, summarizes the certification 

test requirements and performance specifications for a Hg CEMS. 

The CEMS may not be used to report quality-assured data until 

these performance criteria are met. Paragraphs 4.1.1.1 through 

4.1.1.5 of this section provide specific instructions for the 

required tests. All tests must be performed with the affected 

unit(s) operating (i.e., combusting fuel). Except for the RATA, 

which must be performed at normal load, no particular load level 

is required for the certification tests. 

4.1.1.1 7-Day Calibration Error Test. Perform the 7-day 

calibration error test on 7 consecutive source operating days, 

using a zero-level gas and either a high-level or a mid-level 

calibration gas standard (as defined in sections 3.1.8, 3.1.10, 

and 3.1.11 of this appendix). Either elemental or oxidized NIST-
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traceable Hg standards (as defined in sections 3.1.4 and 3.1.5 

of this appendix) may be used for the test. If moisture and/or 

chlorine is added to the calibration gas, the dilution effect of 

the moisture and/or chlorine addition on the calibration gas 

concentration must be accounted for in an appropriate manner. 

Operate the Hg CEMS in its normal sampling mode during the test. 

The calibrations should be approximately 24 hours apart, unless 

the 7-day test is performed over nonconsecutive calendar days. 

On each day of the test, inject the zero-level and upscale gases 

in sequence and record the analyzer responses. Pass the 

calibration gas through all filters, scrubbers, conditioners, 

and other monitor components used during normal sampling, and 

through as much of the sampling probe as is practical. Do not 

make any manual adjustments to the monitor (i.e., resetting the 

calibration) until after taking measurements at both the zero 

and upscale concentration levels. If automatic adjustments are 

made following both injections, conduct the calibration error 

test such that the magnitude of the adjustments can be 

determined, and use only the unadjusted analyzer responses in 

the calculations. Calculate the calibration error (CE) on each 

day of the test, as described in Table A-1. The CE on each day 

of the test must either meet the main performance specification 

or the alternative specification in Table A-1.
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4.1.1.2 Linearity Check. Perform the linearity check using low, 

mid, and high-level concentrations of NIST-traceable elemental 

Hg standards. Three gas injections at each concentration level 

are required, with no two successive injections at the same 

concentration level. Introduce the calibration gas at the gas 

injection port, as specified in section 3.2.1.1.3.6 of this 

appendix. Operate the CEMS at its normal operating temperature 

and conditions. Pass the calibration gas through all filters, 

scrubbers, conditioners, and other components used during normal 

sampling, and through as much of the sampling probe as is 

practical. If moisture and/or chlorine is added 

to the calibration gas, the dilution effect of the moisture 

and/or chlorine addition on the calibration gas concentration 

must be accounted for in an appropriate manner. Record the 

monitor response from the data acquisition and handling system 

for each gas injection. At each concentration level, use the 

average analyzer response to calculate the linearity error (LE), 

as described in Table A-1. The LE must either meet the main 

performance specification or the alternative specification in 

Table A-1.

4.1.1.3 Three-Level System Integrity Check. Perform the 3-level 

system integrity check using low, mid, and high-level 

calibration gas concentrations generated by a NIST-traceable 
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source of oxidized Hg. Follow the same basic procedure as for 

the linearity check. If moisture and/or chlorine is added to the 

calibration gas, the dilution effect of the moisture and/or 

chlorine addition on the calibration gas concentration must be 

accounted for in an appropriate manner. Calculate the system 

integrity error 

(SIE), as described in Table A-1. The SIE must either meet the 

main performance specification or the alternative specification 

in Table A-1. (Note: This test is not required if the CEMS does 

not have a converter).

Table A-1: Required Certification Tests and Performance 

Specifications for Hg CEMS

For this 

required 

certifica

tion 

test.....

The main 

performance 

specification1

is.....

The alternate 

performance 

specification1

is.....

And the 

conditions of 

the alternate 

specification 

are.....

7-day 

calibrati

on error 

test2

|R - A| ≤ 5.0% 

of span value, 

for both the 

zero and 

upscale gases, 

on each of the 

7 days

|R - A| 

≤1.0μg/scm

The alternate 

specification 

may be used on 

any day of the 

test.

Linearity 

check3

|R - Aavg | ≤ 

10.0% of the 

reference gas 

concentration

at each 

calibration 

gas level 

(low, mid, or 

high)

|R - Aavg | ≤ 0.8 

μg/scm

The alternate 

specification 

may be used at 

any gas level
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3-level 

system 

integrity 

check4

|R - Aavg | ≤ 

10.0% of the 

reference gas 

concentration 

at each 

calibration 

gas level 

|R - Aavg | ≤ 0.8 

μg/scm

The alternate 

specification 

may be used at 

any gas level

RATA 20.0% RA |RMavg - Cavg | ≤ 

1.0 μg/scm**

RMavg < 5.0 

μg/scm

Cycle 

time 

test2

15 minutes5 ------------------

-----------

-------------

--------------

-

1 Note that |R - A|is the absolute value of the difference 

between the reference gas value and the analyzer reading. |R -

Aavg| is the absolute value of the difference between the 

reference gas concentration and the average of the analyzer 

responses, at a particular gas level.

2 Use either elemental or oxidized Hg standards; a mid-level or 

high-level upscale gas may be used. This test is not required 

for Hg CEMS that use integrated batch sampling; however, those 

monitors must be capable of recording at least one Hg 

concentration reading every 15 minutes.

3 Use elemental Hg standards. 

4 Use oxidized Hg standards. Not required if the CEMS does not 

have a converter.

5 Stability criteria---Readings change by < 2.0% of span or by ≤ 

0.5 μg/scm, for 2 minutes. 

** Note that |RMavg - Cavg| is the absolute difference between the 

mean reference method value and the mean CEMS value from the 

RATA. The arithmetic difference between RMavg and Cavg can be 

either + or -. 

4.1.1.4 Cycle Time Test. Perform the cycle time test, using a 

zero-level gas and a high-level calibration gas. 

Either an elemental or oxidized NIST-traceable Hg standard may 

be used as the high-level gas. Perform the test in two stages--

upscale and downscale. The slower of the upscale and downscale 

response times is the cycle time for the CEMS. Begin each stage 

of the test by injecting calibration gas after achieving a 
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stable reading of the stack emissions. The cycle time is the 

amount of time it takes for the analyzer to register a reading 

that is 95 percent of the way between the stable stack emissions 

reading and the final, stable reading of the calibration gas 

concentration. Use the following criterion to determine when a 

stable reading of stack emissions or calibration gas has been 

attained -- the reading is stable if it changes by no more than 

2.0 percent of the span value or 0.5 μg/scm (whichever is less 

restrictive) for two minutes, or a reading with a change of less 

than 6.0 percent from the measured average concentration over 6 

minutes. Integrated batch sampling type Hg CEMS are exempted 

from this test; however, these systems must be capable of 

delivering a measured Hg concentration reading at least once 

every 15 minutes. If necessary to increase measurement 

sensitivity of a batch sampling type Hg CEMS for a specific 

application, you may petition the Administrator for approval of 

a time longer than 15 minutes between readings.

4.1.1.5 Relative Accuracy Test Audit (RATA). Perform the RATA of 

the Hg CEMS at normal load. Acceptable Hg reference methods for 

the RATA include ASTM D6784-02 (Reapproved 2008), “Standard Test 

Method for Elemental, Oxidized, Particle-Bound and Total Mercury 

in Flue Gas Generated from Coal-Fired Stationary Sources

(Ontario Hydro Method)” (incorporated by reference, see §63.14)
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and Methods 29, 30A, and 30B in appendix A-8 to Part 60. When 

Method 29 or ASTM D6784-02 is used, paired sampling trains are 

required. To validate a Method 29 or ASTM D6784-02 test run, 

calculate the relative deviation (RD) using Equation A-1 of this

section, and assess the results as follows to validate the run. 

The RD must not exceed 10 percent, when the average Hg 

concentration is greater than 1.0 μg/dscm. If the average 

concentration is ≤ 1.0 μg/dscm, the RD must not exceed 20 

percent. The RD results are also acceptable if the absolute 

difference between the two Hg concentrations does not exceed 0.2 

μg/dscm. If the RD specification is met, the results of the two 

samples shall be averaged arithmetically.

x 100

C C

C C

RD

a b

a b





 (Eq. A-1)

Where: 

RD = Relative deviation between the Hg concentrations of samples 

“a” and “b” (percent)

Ca = Hg concentration of Hg sample “a” (μg/dscm) 

Cb = Hg concentration of Hg sample “b” (μg/dscm)

4.1.1.5.1 Special Considerations. A minimum of nine valid test 

runs must be performed, directly comparing the CEMS measurements 

to the reference method. More than nine test runs may be 

performed. If this option is chosen, the results from a maximum 

of three test runs may be rejected so long as the total number 

of test results used to determine the relative accuracy is 
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greater than or equal to nine; however, all data must be 

reported including the rejected data. The minimum time per run 

is 21 minutes if Method 30A is used. If Method 29, Method 30B, 

or ASTM D6784-02 (Reapproved 2008), “Standard Test Method for 

Elemental, Oxidized, Particle-Bound and Total Mercury in Flue 

Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro 

Method)” (incorporated by reference, see §63.14) is used, the 

time per run must be long enough to collect a sufficient mass of 

Hg to analyze. Complete the RATA within 168 unit operating 

hours, except when Method 29 or ASTM D6784-02 is used, in which 

case up to 336 operating hours may be taken to finish the test.

4.1.1.5.2 Calculation of RATA Results. Calculate the relative 

accuracy (RA) of the monitoring system, on a μg/scm basis, as 

described in section 12 of Performance Specification (PS) 2 in 

Appendix B to Part 60 of this chapter (see Equations 2-3 through 

2-6 of PS2). For purposes of calculating the relative accuracy, 

ensure that the reference method and monitoring system data are 

on a consistent moisture basis, either wet or dry. The CEMS must 

either meet the main performance specification or the 

alternative specification in Table A-1.

4.1.1.5.3 Bias Adjustment. Measurement or adjustment of Hg CEMS 

data for bias is not required.

4.1.2 Sorbent Trap Monitoring Systems. For the initial 
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certification of a sorbent trap monitoring system, only a RATA 

is required.

4.1.2.1 Reference Methods. The acceptable reference methods for 

the RATA of a sorbent trap monitoring system are the same as 

those listed in paragraph 4.1.1.5 of this section.

4.1.2.2 Special Considerations. The special considerations 

specified in paragraph 4.1.1.5.1 of this section apply to the 

RATA of a sorbent trap monitoring system. During the RATA, the 

monitoring system must be operated and quality-assured in 

accordance with Performance Specification (PS) 12B in Appendix B 

to Part 60 of this chapter with the following exceptions for 

sorbent trap section 2 breakthrough:

4.1.2.2.1 For stack Hg concentrations >1 μg/dscm, ≤10% of 

section 1 Hg mass;

4.1.2.2.2 For stack Hg concentrations ≤1 μg/dscm and >0.5 

μg/dscm, ≤ 20% of section 1 Hg mass;

4.1.2.2.3 For stack Hg concentrations ≤0.5 μg/dscm and >0.1 

μg/dscm, ≤ 50% of section 1 Hg mass; and 

4.1.2.2.4 For stack Hg concentrations ≤ 0.1μg/dscm, no 

breakthrough criterion assuming all other QA/QC specifications 

are met.

4.1.2.3 The type of sorbent material used by the traps during 

the RATA must be the same as for daily operation of the 
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monitoring system; however, the size of the traps used for the 

RATA may be smaller than the traps used for daily operation of 

the system.

4.1.2.4 Calculation of RATA Results. Calculate the relative 

accuracy (RA) of the sorbent trap monitoring system, on a μg/scm 

basis, as described in section 12 of Performance Specification 

(PS) 2 in appendix B to Part 60 of this chapter (see Equations 

2-3 through 2-6 of PS2). For purposes of calculating the 

relative accuracy, ensure that the reference method and 

monitoring system data are on a consistent moisture basis, 

either wet or dry.The main and alternative RATA performance 

specifications in Table A-1 for Hg CEMS also apply to the 

sorbent trap monitoring system.

4.1.2.5 Bias Adjustment. Measurement or adjustment of sorbent 

trap monitoring system data for bias is not required.

4.1.3 Diluent Gas, Flow Rate, and/or Moisture Monitoring 

Systems. Monitoring systems that are used to measure stack gas 

volumetric flow rate, diluent gas concentration, or stack gas 

moisture content, either for routine operation of a sorbent trap 

monitoring system or to convert Hg concentration data to units 

of the applicable emission limit, must be certified in 

accordance with the applicable provisions of Part 75 of this 

chapter.
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4.2 Recertification. Whenever the owner or operator makes a 

replacement, modification, or change to a certified CEMS or 

sorbent trap monitoring system that may significantly affect the 

ability of the system to accurately measure or record pollutant 

or diluent gas concentrations, stack gas flow rates, or stack 

gas moisture content, the owner or operator shall recertify the 

monitoring system. Furthermore, whenever the owner or operator 

makes a replacement, modification, or change to the flue gas 

handling system or the unit operation that may significantly 

change the concentration or flow profile, the owner or operator 

shall recertify the monitoring system. The same tests performed 

for the initial certification of the monitoring system shall be 

repeated for recertification, unless otherwise specified by the 

Administrator. Examples of changes that require recertification 

include: replacement of a gas analyzer; complete monitoring 

system replacement, and changing the location or orientation of 

the sampling probe.

5. Ongoing Quality Assurance (QA) and Data Validation

5.1 Hg CEMS.

5.1.1 Required QA Tests. Periodic QA testing of each Hg CEMS is 

required following initial certification. The required QA tests, 

the test frequencies, and the performance specifications that 

must be met are summarized in Table A-2, below. All tests must 
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be performed with the affected unit(s) operating (i.e., 

combusting fuel). Except for the RATA, which must be performed 

at normal load, no particular load level is required for the 

tests. For each test, follow the same basic procedures in 

section 4.1.1 of this appendix that were used for initial 

certification.

5.1.2 Test Frequency. The frequency for the required QA tests of 

the Hg CEMS shall be as follows:

5.1.2.1 Calibration error tests of the Hg CEMS are required 

daily, except during unit outages. Use either NIST-traceable 

elemental Hg standards or NIST-traceable oxidized Hg standards 

for these calibrations. Both a zero-level gas and either a midlevel or high-level gas are required for these calibrations. 

5.1.2.2 Perform a linearity check of the Hg CEMS in each QA 

operating quarter, using low-level, mid-level, and high-level 

NIST-traceable elemental Hg standards. For units that operate 

infrequently, limited exemptions from this test are allowed for 

“non-QA operating quarters”. A maximum of three consecutive 

exemptions for this reason are permitted, following the quarter 

of the last test. After the third consecutive exemption, a 

linearity check must be performed in the next calendar quarter 

or within a grace period of 168 unit or stack operating hours 

after the end of that quarter. The test frequency for 3-level 
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system integrity checks (if performed in lieu of linearity 

checks) is the same as for the linearity checks. Use low-level, 

mid-level, and high-level NIST-traceable oxidized Hg standards 

for the system integrity checks.

5.1.2.3 If required, perform a single-level system integrity 

check weekly, i.e., once every 7 operating days (see the third 

column in Table A-2).

5.1.2.4 The test frequency for the RATAs of the Hg CEMS shall be 

annual, i.e., once every four QA operating quarters. For units 

that operate infrequently, extensions of RATA deadlines are 

allowed for non-QA operating quarters. Following a RATA, if 

there is a subsequent nonQA quarter, it extends the deadline for the next test by 

one calendar quarter. However, there is a limit to these 

extensions; the deadline may not be extended beyond the end of 

the eighth calendar quarter after the quarter of the last test. 

At that point, a RATA must either be performed within the eighth 

calendar quarter or in a 720 hour unit or stack operating hour 

grace period following that quarter. When a required annual RATA 

is done within a grace period, the deadline for the next RATA is 

three QA operating quarters after the quarter in which the grace 

period test is performed.

5.1.3 Grace Periods.
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5.1.3.1 A 168 unit or stack operating hour grace period is 

available for quarterly linearity checks and 3-level system 

integrity checks of the Hg CEMS.

5.1.3.2 A 720 unit or stack operating hour grace period is 

available for RATAs of the Hg CEMS.

5.1.3.3 There is no grace period for weekly system integrity 

checks. The test must be completed once every 7 operating days. 

5.1.4 Data Validation. The Hg CEMS is considered to be out-ofcontrol, and data from the CEMS may not be reported as qualityassured, when any one of the acceptance criteria for the 

required QA tests in Table A-2 is not met. The CEMS is also 

considered to be out-of-control when a required QA test is not 

performed on schedule or within an allotted grace period. To end 

an out-of-control period, the QA test that was either failed or 

not done on time must be performed and passed. Out-of-control 

periods are counted as hours of monitoring system downtime.

5.1.5 Conditional Data Validation. For certification, 

recertification, and diagnostic testing of Hg monitoring 

systems, and for the required QA tests when non-redundant backup 

Hg monitoring systems or temporary like-kind Hg analyzers are 

brought into service, the conditional data validation provisions 

in §§75.20(b)(3)(ii) through (b)(3)(ix) of this chapter may be 

used to avoid or minimize data loss. The allotted window of time 
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to complete 7-day calibration error tests, linearity checks, 

cycle time tests, and RATAs shall be as specified in 

§75.20(b)(3)(iv) of this chapter. Required system integrity

Table A-2: On-Going QA Test Requirements for Hg CEMS

Perform this 

type of QA 

test....

At this 

frequency

....

With these 

qualifications and 

exceptions....

Acceptance 

criteria....

Calibration 

error test Daily 

 Use either a 

mid- or highlevel gas

 Use either 

elemental or 

oxidized Hg

 Calibrations are 

not required when 

the unit is not in 

operation. 

|R - A| ≤ 5.0% 

of span value

or

|R - A| ≤ 

1.0μg/scm

Single-level 

system 

integrity 

check

Weekly1

 Required only 

for systems with 

converters

 Use oxidized Hg 

---either mid- or 

high-level 

 Not required if 

daily calibrations 

are done with a 

NIST-traceable 

source of oxidized 

Hg

|R - Aavg| ≤ 

10.0% of the 

reference gas 

value

or

|R - Aavg| ≤ 

0.8 μg/scm
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Linearity 

check

or

3-level 

system 

integrity 

check

Quarterly3

 Required in each 

“QA operating 

quarter”

2 ---and no 

less than once

every 4 calendar 

quarters

 168 operating 

hour grace period 

available

 Use elemental Hg 

for linearity 

check

 Use oxidized Hg 

for system 

integrity check

 For system 

integrity check, 

CEMS must have a 

converter

|R - Aavg | ≤ 

10.0% of the 

reference gas 

value, at each 

calibration 

gas level

or

|R - Aavg| ≤ 

0.8 μg/scm

RATA Annual4

 Test deadline 

may be extended 

for “non-QA 

operating 

quarters”, up to a 

maximum of 8 

quarters from the 

quarter of the 

previous test.

 720 operating 

hour grace period 

available

20.0% RA

or

|RMavg - Cavg | 

≤ 1.0 μg/scm,

if

RMavg < 5.0 

μg/scm

1 “Weekly” means once every 7 operating days. 

2 A “QA operating quarter” is a calendar quarter with at least 

168 unit or stack operating hours. 

3 “Quarterly” means once every QA operating quarter.

4 “Annual” means once every four QA operating quarters .

checks must be completed within 168 unit or stack operating 

hours after the probationary calibration error test.

5.1.6 Adjustment of Span. If you discover that a span adjustment 

is needed (e.g., if the Hg concentration readings exceed the 
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span value for a significant percentage of the unit operating 

hours in a calendar quarter), you must implement the span 

adjustment within 90 days after the end of the calendar quarter 

in which you identify the need for the adjustment. A diagnostic 

linearity check is required within 168 unit or stack operating 

hours after changing the span value.

5.2 Sorbent Trap Monitoring Systems.

5.2.1 Each sorbent trap monitoring system shall be continuously 

operated and maintained in accordance with Performance 

Specification (PS) 12B in appendix B to Part 60 of this chapter. 

The QA/QC criteria for routine operation of the system are 

summarized in Table 12B-1 of PS 12B. Each pair of sorbent traps 

may be used to sample the stack gas for up to 14 operating days.

5.2.2 For ongoing QA, periodic RATAs of the system are required.

5.2.2.1 The RATA frequency shall be annual, i.e., once every 

four QA operating quarters. The provisions in section 5.1.2.4 of 

this appendix pertaining to RATA deadline extensions also apply 

to sorbent trap monitoring systems.

5.2.2.2 The same RATA performance criteria specified in Table A4 for Hg CEMS shall apply to the annual RATAs of the sorbent 

trap monitoring system.

5.2.2.3 A 720 unit or stack operating hour grace period is 

available for RATAs of the monitoring system.
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5.2.3 Data validation for sorbent trap monitoring systems shall 

be done in accordance with Table 12B-1 in Performance 

Specification (PS) 12B in appendix B to Part 60 of this chapter. 

All periods of invalid data shall be counted as hours of 

monitoring system downtime.

5.3 Flow Rate, Diluent Gas, and Moisture Monitoring Systems. The 

on-going QA test requirements for these monitoring systems are 

specified in Part 75 of this chapter (see §§63.10010(b) through 

(d)). 

5.4 QA/QC Program Requirements. The owner or operator shall 

develop and implement a quality assurance/quality control 

(QA/QC) program for the Hg CEMS and/or sorbent trap monitoring 

systems that are used to provide data under this subpart. At a 

minimum, the program shall include a written plan that describes 

in detail (or that refers to separate documents containing) 

complete, step-by-step procedures and operations for the most 

important QA/QC activities. Electronic storage of the QA/QC plan 

is permissible, provided that the information can be made 

available in hard copy to auditors and inspectors. The QA/QC 

program requirements for the diluent gas, flow rate, and 

moisture monitoring systems described in section 3.2.1.3 of this 

appendix are specified in section 1 of appendix B to Part 75 of 

this chapter.
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5.4.1 General Requirements.

5.4.1.1 Preventive Maintenance. Keep a written record of 

procedures needed to maintain the Hg CEMS and/or sorbent trap 

monitoring system(s) in proper operating condition and a 

schedule for those procedures. Include, at a minimum, all 

procedures specified by the manufacturers of the equipment and, 

if applicable, additional or alternate procedures developed for 

the equipment.

5.4.1.2 Recordkeeping and Reporting. Keep a written record 

describing procedures that will be used to implement the 

recordkeeping and reporting requirements of this appendix.

5.4.1.3 Maintenance Records. Keep a record of all testing, 

maintenance, or repair activities performed on any Hg CEMS or 

sorbent trap monitoring system in a location and format suitable 

for inspection. A maintenance log may be used for this purpose. 

The following records should be maintained: date, time, and 

description of any testing, adjustment, repair, replacement, or 

preventive maintenance action performed on any monitoring system 

and records of any corrective actions associated with a monitor 

outage period. Additionally, any adjustment that may 

significantly affect a system’s ability to accurately measure 

emissions data must be recorded (e.g., changing the dilution 

ratio of a CEMS), and a written explanation of the procedures 
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used to make the adjustment(s) shall be kept.

5.4.2 Specific Requirements for Hg CEMS.

5.4.2.1 Daily Calibrations, Linearity Checks and System 

Integrity Checks. Keep a written record of the procedures used 

for daily calibrations of the Hg CEMS. If moisture and/or 

chlorine is added to the Hg calibration gas, document how the 

dilution effect of the moisture and/or chlorine addition on the 

calibration gas concentration is accounted for in an appropriate 

manner. Also keep records of the procedures used to perform 

linearity checks of the Hg CEMS and the procedures for system 

integrity checks of the Hg CEMS. Document how the test results 

are calculated and evaluated.

5.4.2.2 Monitoring System Adjustments. Document how each 

component of the Hg CEMS will be adjusted to provide correct 

responses to calibration gases after routine maintenance, 

repairs, or corrective actions.

5.4.2.3 Relative Accuracy Test Audits. Keep a written record of 

procedures used for RATAs of the Hg CEMS. Indicate the reference 

methods used and document how the test results are calculated 

and evaluated.

5.4.3 Specific Requirements for Sorbent Trap Monitoring Systems.

5.4.3.1 Sorbent Trap Identification and Tracking. Include 

procedures for inscribing or otherwise permanently marking a 
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unique identification number on each sorbent trap, for chain of 

custody purposes. Keep records of the ID of the monitoring 

system in which each sorbent trap is used, and the dates and 

hours of each Hg collection period.

5.4.3.2 Monitoring System Integrity and Data Quality. Document 

the procedures used to perform the leak checks when a sorbent 

trap is placed in service and removed from service. Also 

Document the other QA procedures used to ensure system integrity 

and data quality, including, but not limited to, gas flow meter 

calibrations, verification of moisture removal, and ensuring 

air-tight pump operation. In addition, the QA plan must include 

the data acceptance and quality control criteria in Table 12B-1 

in section 9.0 of Performance Specification (PS) 12B in Appendix 

B to Part 60 of this chapter. All reference meters used to 

calibrate the gas flow meters (e.g., wet test meters) shall be 

periodically recalibrated. Annual, or more frequent, 

recalibration is recommended. If a NIST–traceable calibration 

device is used as a reference flow meter, the QA plan must 

include a protocol for ongoing maintenance and periodic 

recalibration to maintain the accuracy and NIST–traceability of 

the calibrator.

5.4.3.3 Hg Analysis. Explain the chain of custody employed in 

packing, transporting, and analyzing the sorbent traps. Keep 
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records of all Hg analyses. The analyses shall be performed in 

accordance with the procedures described in section 11.0 of 

Performance Specification (PS) 12B in Appendix B to Part 60 of 

this chapter.

5.4.3.4 Data Collection Period. State, and provide the rationale 

for, the minimum acceptable data collection period (e.g., one 

day, one week, etc.) for the size of sorbent trap selected for 

the monitoring. Address such factors as the Hg concentration in 

the stack gas, the capacity of the sorbent trap, and the minimum 

mass of Hg required for the analysis. Each pair of sorbent traps 

may be used to sample the stack gas for up to 14 operating days.

5.4.3.5 Relative Accuracy Test Audit Procedures. Keep records of 

the procedures and details peculiar to the sorbent trap 

monitoring systems that are to be followed for relative accuracy 

test audits, such as sampling and analysis methods.

6. Data Reduction and Calculations

6.1 Data Reduction.

6.1.1 Reduce the data from Hg CEMS to hourly averages, in 

accordance with §60.13(h)(2) of this chapter.

6.1.2 For sorbent trap monitoring systems, determine the Hg 

concentration for each data collection period and assign this 

concentration value to each operating hour in the data 

collection period.
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6.1.3 For any operating hour in which valid data are not 

obtained, either for Hg concentration or for a parameter used in 

the emissions calculations (i.e., flow rate, diluent gas 

concentration, or moisture, as applicable), do not calculate the 

Hg emission rate for that hour. For the purposes of this 

appendix, Part 75 substitute data values are not considered to 

be valid data.

6.1.4 Operating hours in which valid data are not obtained for 

Hg concentration are considered to be hours of monitor downtime. 

The use of substitute data for Hg concentration is not required.

6.2 Calculation of Hg Emission Rates. Use the applicable 

calculation methods in paragraphs 6.2.1 and 6.2.2 of this 

section to convert Hg concentration values to the appropriate 

units of the emission standard.

6.2.1 Heat Input-Based Hg Emission Rates. Calculate hourly heat 

input-based Hg emission rates, in units of lb/TBtu, according to 

sections 6.2.1.1 through 6.2.1.4 of this appendix.

6.2.1.1 Select an appropriate emission rate equation from among 

Equations 19-1 through 19-9 in EPA Method 19 in appendix A-7 to 

Part 60 of this chapter. 

6.2.1.2 Calculate the Hg emission rate in lb/MMBtu, using the 

equation selected from Method 19. Multiply the Hg concentration 

value by 6.24 x 10-11 to convert it from μg/scm to lb/scf. In 
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cases where an appropriate F-factor is not listed in Table 19-2 

of Method 19, you may use F-factors from Table 1 in section 

3.3.5 of appendix F to Part 75 of this chapter, or F-factors 

derived using the procedures in section 3.3.6 of appendix to 

Part 75 of this chapter. Also, for startup and shutdown hours, 

you may calculate the Hg emission rate using the applicable 

diluent cap value specified in section 3.3.4.1 of appendix F to 

Part 75 of this chapter, provided that the diluent gas monitor 

is not out-of-control and the hourly average O2 concentration is 

above 14.0% O2 (19.0% for an IGCC) or the hourly average CO2

concentration is below 5.0% CO2 (1.0% for an IGCC), as 

applicable.

6.2.1.3 Multiply the lb/MMBtu value obtained in section 6.2.1.2 

of this appendix by 106 to convert it to lb/TBtu.

6.2.1.4 The heat input-based Hg emission rate limit in Table 2 

to this subpart must be met on a 30 boiler operating day rolling 

average basis. Use Equation 19-19 in EPA Method 19 to calculate 

the Hg emission rate for each averaging period. The term Ehj in 

Equation 19-19 must be in the units of the applicable emission 

limit. Do not include non-operating hours with zero emissions in 

the average.

6.2.2 Electrical Output-Based Hg Emission Rates. Calculate 

electrical output-based Hg emission limits in units of lb/GWh, 
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according to sections 6.2.2.1 through 6.2.2.3 of this appendix.

6.2.2.1 Calculate the Hg mass emissions for each operating hour 

in which valid data are obtained for all parameters, using 

Equation A-2 of this section (for wet-basis measurements of Hg 

concentration) or Equation A-3 of this section (for dry-basis 

measurements), as applicable:

Mh  K Ch Qh (Equation A-2)

Where:

Mh = Hg mass emission rate for the hour (lb/h)

K = Units conversion constant, 6.24 x 10-11 lb-scm/μg-scf,

Ch = Hourly average Hg concentration, wet basis (μg/scm)

Qh = Stack gas volumetric flow rate for the hour (scfh).

(Note: Use unadjusted flow rate values; bias adjustment is not 

required) 

  Mh  K Ch Qh 1 Bws (Equation A-3)

Where:

Mh = Hg mass emission rate for the hour (lb/h)

K = Units conversion constant, 6.24 x 10-11 lb-scm/μg-scf.

Ch = Hourly average Hg concentration, dry basis (μg/dscm).

Qh = Stack gas volumetric flow rate for the hour (scfh) 

(Note: Use unadjusted flow rate values; bias adjustment is not 

required).

Bws = Moisture fraction of the stack gas, expressed as a decimal 

(equal to % H2O/100)

6.2.2.2 Use Equation A-4 of this section to calculate the 

emission rate for each unit or stack operating hour in which 

valid data are obtained for all parameters. 

 

3

x 10

MW

M

E

h

h

ho  (Equation A-4)
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Where:

Eho = Electrical output-based Hg emission rate (lb/GWh).

Mh = Hg mass emission rate for the hour, from Equation A-2 or A-3

of this section, as applicable (lb/h).

(MW)h = Gross electrical load for the hour, in megawatts (MW).

103 = Conversion factor from megawatts to gigawatts.

6.2.2.3 The applicable electrical output-based Hg emission rate 

limit in Table 1 or 2 to this subpart must be met on a 30-boiler

operating day rolling average basis. Use Equation A-5 of this 

section to calculate the Hg emission rate for each averaging 

period.

n

E

E

n

h

ho

o





1 (Equation A-5)

Where:

Eo = Hg emission rate for the averaging period (lb/GWh).

Echo = Electrical output-based hourly Hg emission rate for unit 

or stack operating hour “h” in the averaging period, from 

Equation A-4 of this section (lb/GWh).

n = Number of unit or stack operating hours in the averaging 

period in which valid data were obtained for all parameters 

(Note: Do not include non-operating hours with zero emission 

rates in the average).

7. Recordkeeping and Reporting

7.1 Recordkeeping Provisions. For the Hg CEMS and/or sorbent 

trap monitoring systems and any other necessary monitoring 

systems installed at each affected unit, the owner or operator 

must maintain a file of all measurements, data, reports, and 

other information required by this appendix in a form suitable 
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for inspection, for 5 years from the date of each record, in 

accordance with §63.10033. The file shall contain the 

information in paragraphs 7.1.1 through 7.1.10 of this section.

7.1.1 Monitoring Plan Records. For each affected unit or group 

of units monitored at a common stack, the owner or operator 

shall prepare and maintain a monitoring plan for the Hg CEMS 

and/or sorbent trap monitoring system(s) and any other 

monitoring system(s) (i.e., flow rate, diluent gas, or moisture 

systems) needed for routine operation of a sorbent trap 

monitoring system or to convert Hg concentrations to units of 

the applicable emission standard. The monitoring plan shall 

contain essential information on the continuous monitoring 

systems and shall Document how the data derived from these 

systems ensure that all Hg emissions from the unit or stack are 

monitored and reported.

7.1.1.1 Updates. Whenever the owner or operator makes a 

replacement, modification, or change in a certified continuous 

monitoring system that is used to provide data under this 

subpart (including a change in the automated data acquisition 

and handling system or the flue gas handling system) which 

affects information reported in the monitoring plan (e.g., a 

change to a serial number for a component of a monitoring 

system), the owner or operator shall update the monitoring plan.
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7.1.1.2 Contents of the Monitoring Plan. For Hg CEMS and sorbent 

trap monitoring systems, the monitoring plan shall contain the 

information in sections 7.1.1.2.1 and 7.1.1.2.2 of this 

appendix, as applicable. For stack gas flow rate, diluent gas, 

and moisture monitoring systems, the monitoring plan shall 

include the information required for those systems under §75.53 

(g) of this chapter. 

7.1.1.2.1 Electronic. The electronic monitoring plan records 

must include the following: unit or stack ID number(s); 

monitoring location(s); the Hg monitoring methodologies used; Hg 

monitoring system information, including, but not limited to: 

unique system and component ID numbers; the make, model, and 

serial number of the monitoring equipment; the sample 

acquisition method; formulas used to calculate Hg emissions; Hg 

monitor span and range information The electronic monitoring 

plan shall be evaluated and submitted using the Emissions 

Collection and Monitoring Plan System (ECMPS) Client Tool 

provided by the Clean Air Markets Division in the Office of 

Atmospheric Programs of the EPA.

7.1.1.2.2 Hard Copy. Keep records of the following: schematics 

and/or blueprints showing the location of the Hg monitoring 

system(s) and test ports; data flow diagrams; test protocols; 

monitor span and range calculations; miscellaneous technical 
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justifications.

7.1.2 Operating Parameter Records. The owner or operator shall 

record the following information for each operating hour of each 

affected unit and also for each group of units utilizing a 

common stack, to the extent that these data are needed to 

convert Hg concentration data to the units of the emission 

standard. For non-operating hours, record only the items in 

paragraphs 7.1.2.1 and 7.1.2.2 of this section. If there is heat 

input to the unit(s), but no electrical load, record only the 

items in paragraphs 7.1.2.1, 7.1.2.2, and (if applicable) 

7.1.2.4 of this section.

7.1.2.1 The date and hour;

7.1.2.2 The unit or stack operating time (rounded up to the 

nearest fraction of an hour (in equal increments that can range 

from one hundredth to one quarter of an hour, at the option of 

the owner or operator);

7.1.2.3 The hourly gross unit load (rounded to nearest MWe); and

7.1.2.4 If applicable, the F-factor used to calculate the heat 

input-based Hg emission rate.

7.1.3 Hg Emissions Records (Hg CEMS). For each affected unit or 

common stack using a Hg CEMS, the owner or operator shall record 

the following information for each unit or stack operating hour:

7.1.3.1 The date and hour;
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7.1.3.2 Monitoring system and component identification codes, as 

provided in the monitoring plan, if the CEMS provides a qualityassured value of Hg concentration for the hour;

7.1.3.3 The hourly Hg concentration, if a quality-assured value 

is obtained for the hour (μg/scm, rounded to three significant 

figures);

7.1.3.4 A special code, indicating whether or not a qualityassured Hg concentration is obtained for the hour. This code may 

be entered manually when a temporary like-kind replacement Hg 

analyzer is used for reporting; and

7.1.3.5 Monitor data availability, as a percentage of unit or 

stack operating hours, calculated according to §75.32 of this 

chapter.

7.1.4 Hg Emissions Records (Sorbent Trap Monitoring Systems). 

For each affected unit or common stack using a sorbent trap 

monitoring system, each owner or operator shall record the 

following information for the unit or stack operating hour in 

each data collection period:

7.1.4.1 The date and hour;

7.1.4.2 Monitoring system and component identification codes, as 

provided in the monitoring plan, if the sorbent trap system 

provides a quality-assured value of Hg concentration for the 

hour;
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7.1.4.3 The hourly Hg concentration, if a quality-assured value 

is obtained for the hour (μg/scm, rounded to three significant 

figures). Note that when a quality-assured Hg concentration 

value is obtained for a particular data collection period, that 

single concentration value is applied to each operating hour of 

the data collection period.

7.1.4.4 A special code, indicating whether or not a qualityassured Hg concentration is obtained for the hour;

7.1.4.5 The average flow rate of stack gas through each sorbent 

trap (in appropriate units, e.g., liters/min, cc/ min, 

dscm/min);

7.1.4.6 The gas flow meter reading (in dscm, rounded to the 

nearest hundredth), at the beginning and end of the collection 

period and at least once in each unit operating hour during the 

collection period;

7.1.4.7 The ratio of the stack gas flow rate to the sample flow 

rate, as described in section 12.2 of Performance Specification 

(PS) 12B in Appendix B to Part 60 of this chapter; and

7.1.4.8 Monitor data availability, as a percentage of unit or 

stack operating hours, calculated according to §75.32 of this 

chapter.

7.1.5 Stack Gas Volumetric Flow Rate Records.

7.1.5.1 Hourly measurements of stack gas volumetric flow rate 
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during unit operation are required for routine operation of 

sorbent trap monitoring systems, to maintain the required ratio 

of stack gas flow rate to sample flow rate (see section 8.2.2 of 

Performance Specification (PS) 12B in Appendix B to Part 60 of 

this chapter). Hourly stack gas flow rate data are also needed 

in order to demonstrate compliance with electrical output-based 

Hg emissions limits, as provided in section 6.2.2 of this 

appendix.

7.1.5.2 For each affected unit or common stack, if hourly 

measurements of stack gas flow rate are needed for sorbent trap 

monitoring system operation or to convert Hg concentrations to 

the units of the emission standard, use a flow rate monitor that 

meets the requirements of Part 75 of this chapter to record the 

required data. You must keep hourly flow rate records, as 

specified in §75.57(c)(2) of this chapter.

7.1.6 Records of Stack Gas Moisture Content.

7.1.6.1 Correction of hourly Hg concentration data for moisture 

is sometimes required when converting Hg concentrations to the 

units of the applicable Hg emissions limit. In particular, these 

corrections are required:

7.1.6.1.1 For sorbent trap monitoring systems;

7.1.6.1.2 For Hg CEMS that measure Hg concentration on a dry 

basis, when you must calculate electrical output-based Hg 
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emission rates; and

7.1.6.1.3 When using certain equations from EPA Method 19 in 

appendix A-7 to Part 60 of this chapter to calculate heat inputbased Hg emission rates.

7.1.6.2 If hourly moisture corrections are required, either use 

a fuel-specific default moisture percentage from §75.11(b)(1) of 

this chapter or a certified moisture monitoring system that 

meets the requirements of Part 75 of this chapter, to record the 

required data. If you use a moisture monitoring system, you must 

keep hourly records of the stack gas moisture content, as 

specified in §75.57(c)(3) of this chapter.

7.1.7 Records of Diluent Gas (CO2 or O2) Concentration.

7.1.7.1 When a heat input-based Hg mass emissions limit must be 

met, in units of lb/TBtu, hourly measurements of CO2 or O2

concentration are required to convert Hg concentrations to units 

of the standard.

7.1.7.2 If hourly measurements of diluent gas concentration are 

needed, use a certified CO2 or O2 monitor that meets the 

requirements of Part 75 of this chapter to record the required 

data. You must keep hourly CO2 or O2 concentration records, as 

specified in §75.57(g) of this chapter.

7.1.8 Hg Emission Rate Records. For applicable Hg emission 

limits in units of lb/TBtu or lb/GWh, record the following 
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information for each affected unit or common stack:

7.1.8.1 The date and hour;

7.1.8.2 The hourly Hg emissions rate (lb/TBtu or lb/GWh, as 

applicable, calculated according to section 6.2.1 or 6.2.2 of 

this appendix, rounded to three significant figures), if valid 

values of Hg concentration and all other required parameters 

(stack gas volumetric flow rate, diluent gas concentration, 

electrical load, and moisture data, as applicable) are obtained 

for the hour;

7.1.8.3 An identification code for the formula (either the 

selected equation from Method 19 in section 6.2.1 of this 

appendix or Equation A-4 in section 6.2.2 of this appendix) used 

to derive the hourly Hg emission rate from Hg concentration, 

flow rate, electrical load, diluent gas concentration, and 

moisture data (as applicable); and

7.1.8.4 A code indicating that the Hg emission rate was not 

calculated for the hour, if valid data for Hg concentration 

and/or any of the other necessary parameters are not obtained 

for the hour. For the purposes of this appendix, the substitute 

data values required under Part 75 of this chapter for diluent 

gas concentration, stack gas flow rate and moisture content are 

not considered to be valid data. 

7.1.9 Certification and Quality Assurance Test Records. For any 
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Hg CEMS and sorbent trap monitoring systems used to provide data 

under this subpart, record the following certification and 

quality-assurance information:

7.1.9.1 The reference values, monitor responses, and calculated 

calibration error (CE) values, and a flag to indicate whether 

the test was done using elemental or oxidized Hg, for all 

required 7-day calibration error tests and daily calibration 

error tests of the Hg CEMS;

7.1.9.2 The reference values, monitor responses, and calculated 

linearity error (LE) or system integrity error (SIE) values for 

all linearity checks of the Hg CEMS, and for all single-level 

and 3-level system integrity checks of the Hg CEMS;

7.1.9.3 The CEMS and reference method readings for each test run 

and the calculated relative accuracy results for all RATAs of 

the Hg CEMS and/or sorbent trap monitoring systems;

7.1.9.4 The stable stack gas and calibration gas readings and 

the calculated results for the upscale and downscale stages of 

all required cycle time tests of the Hg CEMS or, for a batch 

sampling Hg CEMS, the interval between measured Hg concentration 

readings;

7.1.9.5 Supporting information for all required RATAs of the Hg 

monitoring systems, including records of the test dates, the raw 

reference method and monitoring system data, the results of 
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sample analyses to substantiate the reported test results, and 

records of sampling equipment calibrations; 

7.1.9.6 For sorbent trap monitoring systems, also keep records 

of the results of all analyses of the sorbent traps used for 

routine daily operation of the system, and information 

documenting the results of all leak checks and the other 

applicable quality control procedures described in Table 12B-1 

of Performance Specification (PS) 12B in appendix B to Part 60 

of this chapter.

7.1.9.7 For stack gas flow rate, diluent gas, and (if 

applicable) moisture monitoring systems, you must keep records 

of all certification, recertification, diagnostic, and on-going 

quality-assurance tests of these systems, as specified in §75.59 

of this chapter.

7.2 Reporting Requirements.

7.2.1 General Reporting Provisions. The owner or operator shall 

comply with the following requirements for reporting Hg 

emissions from each affected unit (or group of units monitored 

at a common stack) under this subpart:

7.2.1.1 Notifications, in accordance with paragraph 7.2.2 of 

this section;

7.2.1.2 Monitoring plan reporting, in accordance with paragraph 

7.2.3 of this section;
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7.2.1.3 Certification, recertification, and QA test submittals, 

in accordance with paragraph 7.2.4 of this section; and

7.2.1.4 Electronic quarterly report submittals, in accordance 

with paragraph 7.2.5 of this section.

7.2.2 Notifications. The owner or operator shall provide 

notifications for each affected unit (or group of units 

monitored at a common stack) under this subpart in accordance 

with §63.10030.

7.2.3 Monitoring Plan Reporting. For each affected unit (or 

group of units monitored at a common stack) under this subpart 

using Hg CEMS or sorbent trap monitoring system to measure Hg 

emissions, the owner or operator shall make electronic and hard 

copy monitoring plan submittals as follows:

7.2.3.1 Submit the electronic and hard copy information in 

section 7.1.1.2 of this appendix pertaining to the Hg monitoring 

systems at least 21 days prior to the applicable date in 

§63.9984. Also submit the monitoring plan information in §75.53 

(g) pertaining to the flow rate, diluent gas, and moisture 

monitoring systems within that same time frame, if the required 

records are not already in place. 

7.2.3.2 Whenever an update of the monitoring plan is required, 

as provided in paragraph 7.1.1.1 of this section. An electronic 

monitoring plan information update must be submitted either 
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prior to or concurrent with the quarterly report for the 

calendar quarter in which the update is required.

7.2.3.3 All electronic monitoring plan submittals and updates 

shall be made to the Administrator using the ECMPS Client Tool. 

Hard copy portions of the monitoring plan shall be kept on 

record according to section 7.1 of this appendix.

7.2.4 Certification, Recertification, and Quality-Assurance Test 

Reporting. Except for daily QA tests of the required monitoring 

systems (i.e., calibration error tests and flow monitor 

interference checks), the results of all required certification, 

recertification, and quality-assurance tests described in 

paragraphs 7.1.10.1 through 7.1.10.7 of this section (except for 

test results previously submitted, e.g., under the ARP) shall be 

submitted electronically, using the ECMPS Client Tool, either 

prior to or concurrent with the relevant quarterly electronic 

emissions report.

7.2.5 Quarterly Reports.

7.2.5.1 Beginning with the report for the calendar quarter in 

which the initial compliance demonstration is completed or the 

calendar quarter containing the applicable date in §63.9984, the 

owner or operator of any affected unit shall use the ECMPS

Client Tool to submit electronic quarterly reports to the 

Administrator, in an XML format specified by the Administrator, 
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for each affected unit (or group of units monitored at a common 

stack) under this subpart. 

7.2.5.2 The electronic reports must be submitted within 30 days 

following the end of each calendar quarter, except for units 

that have been placed in long-term cold storage.

7.2.5.3 Each electronic quarterly report shall include the 

following information:

7.2.5.3.1 The date of report generation;

7.2.5.3.2 Facility identification information;

7.2.5.3.3 The information in paragraphs 7.1.2 through 7.1.8 of 

this section, as applicable to the Hg emission measurement 

methodology (or methodologies) used and the units of the Hg 

emission standard(s); and

7.2.5.3.4 The results of all daily calibration error tests of 

the Hg CEMS, as described in paragraph 7.1.90.1 of this section 

and (if applicable) the results of all daily flow monitor 

interference checks.

7.2.5.4 Compliance Certification. Based on reasonable inquiry of 

those persons with primary responsibility for ensuring that all 

Hg emissions from the affected unit(s) under this subpart have 

been correctly and fully monitored, the owner or operator shall 

submit a compliance certification in support of each electronic 

quarterly emissions monitoring report. The compliance 
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certification shall include a statement by a responsible 

official with that official’s name, title, and signature, 

certifying that, to the best of his or her knowledge, the report 

is true, accurate, and complete. 

Appendix B to Subpart UUUUU—-HCl and HF Monitoring Provisions

1. Applicability

These monitoring provisions apply to the measurement of HCl 

and/or HF emissions from electric utility steam generating 

units, using CEMS. The CEMS must be capable of measuring HCl 

and/or HF in the appropriate units of the applicable emissions 

standard (e.g., lb/MMBtu, lb/MWh, or lb/GWh). 

2. Monitoring of HCl and/or HF Emissions

2.1 Monitoring System Installation Requirements. Install HCl 

and/or HF CEMS and any additional monitoring systems needed to 

convert pollutant concentrations to units of the applicable 

emissions limit in accordance with Performance Specification 15

for extractive Fourier Transform Infrared Spectroscopy (FTIR) 

continuous emissions monitoring systems in appendix B to part 60 

of this chapter and §63.10010(a). 

2.2 Primary and Backup Monitoring Systems. The provisions 

pertaining to primary and redundant backup monitoring systems in 

section 2.2 of appendix A to this subpart apply to HCl and HF 

CEMS and any additional monitoring systems needed to convert 
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pollutant concentrations to units of the applicable emissions 

limit.

2.3 FTIR Monitoring System Equipment, Supplies, Definitions, and 

General Operation. The provisions of Performance Specification 

15 Sections 2.0, 3.0, 4.0, 5.0, 6.0, and 10.0 apply.

3. Initial Certification Procedures

The initial certification procedures for the HCl or HF CEMS used 

to provide data under this subpart are as follows:

3.1 The HCl and/or HF CEMS must be certified according to 

Performance Specification 15 using the procedures for gas 

auditing and comparison to a reference method (RM) as specified 

in sections 3.1.1 and 3.1.2 below. (Please Note: EPA plans to 

publish a technology neutral performance specification and 

appropriate on-going quality-assurance requirements for HCl CEMS 

in the near future along with amendments to this appendix to 

accommodate their use.)

3.1.1 You must conduct a gas audit of the HCl and/or HF CEMS as 

described in section 9.1 of Performance Specification 15, with 

the exceptions listed in sections 3.1.2.1 and 3.1.2.2 below. 

3.1.1.1 The audit sample gas does not have to be obtained from 

the Administrator; however, it must be (1) from a secondary 

source of certified gases (i.e., independent of any calibration 

gas used for the daily calibration assessments) and (2) directly 
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traceable to National Institute of Standards and Technology 

(NIST) or VSL Dutch Metrology Institute (VSL) reference 

materials through an unbroken chain of comparisons. If audit gas 

traceable to NIST or VSL reference materials is not available, 

you may use a gas with a concentration certified to a specified 

uncertainty by the gas manufacturer. 

3.1.1.2 Analyze the results of the gas audit using the 

calculations in section 12.1 of Performance Specification 15. 

The calculated correction factor (CF) from Eq. 6 of Performance 

Specification 15 must be between 0.85 and 1.15. You do not have 

to test the bias for statistical significance.

3.1.2 You must perform a relative accuracy test audit or RATA 

according to section 11.1.1.4 of Performance Specification 15

and the requirements below. Perform the RATA of the HCl or HF 

CEMS at normal load. Acceptable HCl/HF reference methods (RM) 

are Methods 26 and 26A in appendix A-8 to part 60 of this 

chapter, Method 320 in Appendix A to this part, or ASTM D6348-03 

“Standard Test Method for Determination of Gaseous Compounds by 

Extractive Direct Interface Fourier Transform Infrared (FTIR) 

Spectroscopy”, each applied based on the criteria set forth in 

Table 5 of this subpart. 

3.1.2.1 When ASTM D6348-03 is used as the RM, the following 

conditions must be met:
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3.1.2.1.1 The test plan preparation and implementation in the 

Annexes to ASTM D6348-03, Sections A1 through A8 are mandatory;

3.1.2.1.2 In ASTM D6348-03 Annex A5 (Analyte Spiking Technique), 

the percent (%) R must be determined for each target analyte 

(see Equation A5.5);

3.1.2.1.3 For the ASTM D6348-03 test data to be acceptable for a 

target analyte, %R must be 70 % ≥ R ≤ 130%; and

3.1.2.1.4 The %R value for each compound must be reported in the 

test report and all field measurements corrected with the 

calculated %R value for that compound using the following 

equation:

 

% R x 100

M e a s u r e d C o n c e n tr a tio n in S ta c k

R e p o r te d R e s u lt

 (Eq. B-1)

3.1.2.2 The relative accuracy (RA) of the HCl or HF CEMS must be 

no greater than 20 percent of the mean value of the RM test data 

in units of ppm on the same moisture basis. Alternatively, if 

the mean RM value is less than 1.0 ppm, the RA results are 

acceptable if the absolute value of the difference between the 

mean RM and CEMS values does not exceed 0.20 ppm.

3.2 Any additional stack gas flow rate, diluent gas, and 

moisture monitoring system(s) needed to express pollutant 

concentrations in units of the applicable emissions limit must 

be certified according to part 75 of this chapter.
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4. Recertification Procedures

Whenever the owner or operator makes a replacement, 

modification, or change to a certified CEMS that may 

significantly affect the ability of the system to accurately 

measure or record pollutant or diluent gas concentrations, stack 

gas flow rates, or stack gas moisture content, the owner or 

operator shall recertify the monitoring system. Furthermore, 

whenever the owner or operator makes a replacement, 

modification, or change to the flue gas handling system or the 

unit operation that may significantly change the concentration 

or flow profile, the owner or operator shall recertify the 

monitoring system. The same tests performed for the initial 

certification of the monitoring system shall be repeated for 

recertification, unless otherwise specified by the 

Administrator. Examples of changes that require recertification 

include: replacement of a gas analyzer; complete monitoring 

system replacement, and changing the location or orientation of 

the sampling probe.

5. On-Going Quality Assurance Requirements

5.1 For on-going QA test requirements for HCl and HF CEMS,

implement the quality assurance/quality control procedures of 

Performance Specification 15 of appendix B to part 60 of this 

chapter as set forth in sections 5.1.1 through 5.1.3 and 5.3.2 
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of this appendix. 

5.1.1 On a daily basis, you must assess the calibration error of 

the HCl or HF CEMS using either a calibration transfer standard 

as specified in Performance Specification 15 Section 10.1 which 

references Section 4.5 of the FTIR Protocol or a HCl and/or HF 

calibration gas at a concentration no greater than two times the 

level corresponding to the applicable emission limit. A 

calibration transfer standard is a substitute calibration 

compound chosen to ensure that the FTIR is performing well at 

the wavelength regions used for analysis of the target analytes. 

The measured concentration of the calibration transfer standard 

or HCl and/or HF calibration gas results must agree within + 5 

percent of the reference gas value after correction for 

differences in pressure.

5.1.2 On a quarterly basis, you must conduct a gas audit of the 

HCl and/or HF CEMS as described in section 3.1.1 of this 

appendix. For the purposes of this appendix, “quarterly” means 

once every “QA operating quarter” (as defined in section 3.1.20 

of appendix A to this subpart). You have the option to use HCl 

gas in lieu of HF gas for conducting this audit on an HF CEMS. 

To the extent practicable, perform consecutive quarterly gas 

audits at least 30 days apart. The initial quarterly audit is 

due in the first QA operating quarter following the calendar 
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quarter in which certification testing of the CEMS is 

successfully completed. Up to three consecutive exemptions from 

the quarterly audit requirement are allowed for “non-QA 

operating quarters” (i.e., calendar quarters in which there are 

less than 168 unit or stack operating hours). However, no more 

than four consecutive calendar quarters may elapse without 

performing a gas audit, except as otherwise provided in section 

5.3.3.2.1 of this appendix.

5.1.3 You must perform an annual relative accuracy test audit or 

RATA of the HCl or HF CEMS as described in section 3.1.2 of this 

appendix. Perform the RATA at normal load. For the purposes of 

this appendix, “annual” means once every four “QA operating 

quarters” (as defined in section 3.1.20 of appendix A to this 

subpart). The first annual RATA is due within four QA operating 

quarters following the calendar quarter in which the initial 

certification testing of the HCl or HF CEMS is successfully 

completed. The provisions in section 5.1.2.4 of appendix A to 

this subpart pertaining to RATA deadline extensions also apply.

5.2 Stack gas flow rate, diluent gas, and moisture monitoring 

systems must meet the applicable on-going QA test requirements 

of part 75 of this chapter.

5.3 Data Validation. 

5.3.1 Out-of-Control Periods. A HCl or HF CEMS that is used to 
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provide data under this appendix is considered to be out-ofcontrol, and data from the CEMS may not be reported as qualityassured, when any acceptance criteria for a required QA test is

not met. The HCl or HF CEMS is also considered to be out-ofcontrol when a required QA test is not performed on schedule or 

within an allotted grace period. To end an out-of-control 

period, the QA test that was either failed or not done on time 

must be performed and passed. Out-of-control periods are counted 

as hours of monitoring system downtime.

5.3.2 Grace Periods. For the purposes of this appendix, a “grace 

period” is defined as a specified number of unit or stack 

operating hours after the deadline for a required qualityassurance test of a continuous monitor has passed, in which the 

test may be performed and passed without loss of data.

5.3.2.1 For the flow rate, diluent gas, and moisture monitoring 

systems described in section 5.2 of this appendix, a 168 unit or 

stack operating hour grace period is available for quarterly 

linearity checks, and a 720 unit or stack operating hour grace 

period is available for RATAs, as provided, respectively, in 

sections 2.2.4 and 2.3.3 of appendix B to part 75 of this 

chapter.

5.3.2.2 For the purposes of this appendix, if the deadline for a 

required gas audit or RATA of a HCl or HF CEMS cannot be met due 
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to circumstances beyond the control of the owner or operator:

5.3.2.2.1 A 168 unit or stack operating hour grace period is 

available in which to perform the gas audit; or

5.3.2.2.2 A 720 unit or stack operating hour grace period is 

available in which to perform the RATA. 

5.3.2.3 If a required QA test is performed during a grace 

period, the deadline for the next test shall be determined as 

follows:

5.3.2.3.1 For a gas audit or RATA of the monitoring systems 

described in section 5.1 of this appendix, determine the 

deadline for the next gas audit or RATA (as applicable) in 

accordance with section 2.2.4(b) or 2.3.3(d) of appendix B to 

part 75 of this chapter; treat a gas audit in the same manner as 

a linearity check.

5.3.2.3.2 For the gas audit of a HCl or HF CEMS, the grace 

period test only satisfies the audit requirement for the 

calendar quarter in which the test was originally due. If the 

calendar quarter in which the grace period audit is performed is 

a QA operating quarter, an additional gas audit is required for 

that quarter.

5.3.2.3.3 For the RATA of a HCl or HF CEMS, the next RATA is due 

within three QA operating quarters after the calendar quarter in 

which the grace period test is performed.
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5.3.4 Conditional Data Validation. For recertification and 

diagnostic testing of the monitoring systems that are used to 

provide data under this appendix, and for the required QA tests 

when non-redundant backup monitoring systems or temporary likekind replacement analyzers are brought into service, the 

conditional data validation provisions in §§75.20(b)(3)(ii) 

through (b)(3)(ix) of this chapter may be used to avoid or 

minimize data loss. The allotted window of time to complete 

calibration tests and RATAs shall be as specified in 

§75.20(b)(3)(iv) of this chapter; the allotted window of time to 

complete a gas audit shall be the same as for a linearity check 

(i.e., 168 unit or stack operating hours).

6. Missing Data Requirements

For the purposes of this appendix, the owner or operator of an 

affected unit shall not substitute for missing data from HCl or 

HF CEMS. Any process operating hour for which quality-assured

HCl or HF concentration data are not obtained is counted as an 

hour of monitoring system downtime. 

7. Bias Adjustment

Bias adjustment of hourly emissions data from a HCl or HF CEMS 

is not required. 

8. QA/QC Program Requirements 

The owner or operator shall develop and implement a quality 
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assurance/quality control (QA/QC) program for the HCl and/or HF 

CEMS that are used to provide data under this subpart. At a 

minimum, the program shall include a written plan that describes 

in detail (or that refers to separate documents containing) 

complete, step-by-step procedures and operations for the most 

important QA/QC activities. Electronic storage of the QA/QC plan 

is permissible, provided that the information can be made

available in hard copy to auditors and inspectors. The QA/QC 

program requirements for the other monitoring systems described 

in section 5.2 of this appendix are specified in section 1 of 

appendix B to part 75 of this chapter. 

8.1 General Requirements for HCl and HF CEMS.

8.1.1 Preventive Maintenance. Keep a written record of 

procedures needed to maintain the HCl and/or HF CEMS in proper 

operating condition and a schedule for those procedures. This 

shall, at a minimum, include procedures specified by the 

manufacturers of the equipment and, if applicable, additional or 

alternate procedures developed for the equipment.

8.1.2 Recordkeeping and Reporting. Keep a written record 

describing procedures that will be used to implement the 

recordkeeping and reporting requirements of this appendix.

8.1.3 Maintenance Records. Keep a record of all testing, 

maintenance, or repair activities performed on any HCl or HF 
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CEMS in a location and format suitable for inspection. A 

maintenance log may be used for this purpose. The following 

records should be maintained: date, time, and description of any 

testing, adjustment, repair, replacement, or preventive 

maintenance action performed on any monitoring system and 

records of any corrective actions associated with a monitor 

outage period. Additionally, any adjustment that may 

significantly affect a system’s ability to accurately measure 

emissions data must be recorded and a written explanation of the 

procedures used to make the adjustment(s) shall be kept.

8.2 Specific Requirements for HCl and HF CEMS. The following 

requirements are specific to HCl and HF CEMS:

8.2.1 Keep a written record of the procedures used for each type 

of QA test required for each HCl and HF CEMS. Explain how the 

results of each type of QA test are calculated and evaluated.

8.2.2 Explain how each component of the HCl and/or HF CEMS will 

be adjusted to provide correct responses to calibration gases 

after routine maintenance, repairs, or corrective actions.

9. Data Reduction and Calculations

9.1 Design and operate the HCl and/or HF CEMS to complete a 

minimum of one cycle of operation (sampling, analyzing, and data 

recording) for each successive 15-minute period.

9.2 Reduce the HCl and/or HF concentration data to hourly 
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averages in accordance with §60.13(h)(2) of this chapter. 

9.3 Convert each hourly average HCl or HF concentration to an 

HCl or HF emission rate expressed in units of the applicable 

emissions limit. 

9.3.1 For heat input-based emission rates, select an appropriate 

emission rate equation from among Equations 19-1 through 19-9 in 

EPA Method 19 in appendix A-7 to part 60 of this chapter, to 

calculate the HCl or HF emission rate in lb/MMBtu. Multiply the 

HCl concentration value (ppm) by 9.43 x 10-8 to convert it to 

lb/scf, for use in the applicable Method 19 equation. For HF, 

the conversion constant from ppm to lb/scf is 5.18 x 10-8.

9.3.2 For electrical output-based emission rates, first 

calculate the HCl or HF mass emission rate (lb/h), using an 

equation that has the general form of Equation A-2 or A-3 in 

appendix A to this subpart (as applicable), replacing the value 

of K with 9.43 x 10-8 lb/scf-ppm (for HCl) or 5.18 x 10-8 (for HF)

and defining Ch as the hourly average HCl or HF concentration in 

ppm. Then, use Equation A-4 in appendix A to this subpart to 

calculate the HCl or HF emission rate in lb/GWh. If the 

applicable HCl or HF limit is expressed in lb/MWh, divide the 

result from Equation A-4 by 103.

9.4 Use Equation A-5 in appendix A of this subpart to calculate 

the required 30 operating day rolling average HCl or HF emission 
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rates. Round off each 30 operating day average to two 

significant figures. The term Eho in Equation A-5 must be in the 

units of the applicable emissions limit.

10. Recordkeeping Requirements

10.1 For each HCl or HF CEMS installed at an affected source, 

and for any other monitoring system(s) needed to convert 

pollutant concentrations to units of the applicable emissions 

limit, the owner or operator must maintain a file of all 

measurements, data, reports, and other information required by 

this appendix in a form suitable for inspection, for 5 years 

from the date of each record, in accordance with §63.10033. The 

file shall contain the information in paragraphs 10.1.1 through 

10.1.8 of this section.

10.1.1 Monitoring Plan Records. For each affected unit or group 

of units monitored at a common stack, the owner or operator 

shall prepare and maintain a monitoring plan for the HCl and/or 

HF CEMS and any other monitoring system(s) (i.e, flow rate, 

diluent gas, or moisture systems) needed to convert pollutant 

concentrations to units of the applicable emission standard. The 

monitoring plan shall contain essential information on the 

continuous monitoring systems and shall explain how the data 

derived from these systems ensure that all HCl or HF emissions 

from the unit or stack are monitored and reported.
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10.1.1.1 Updates. Whenever the owner or operator makes a 

replacement, modification, or change in a certified continuous 

HCl or HF monitoring system that is used to provide data under 

this subpart (including a change in the automated data 

acquisition and handling system or the flue gas handling system) 

which affects information reported in the monitoring plan (e.g., 

a change to a serial number for a component of a monitoring 

system), the owner or operator shall update the monitoring plan.

10.1.1.2 Contents of the Monitoring Plan. For HCl and/or HF

CEMS, the monitoring plan shall contain the applicable 

electronic and hard copy information in sections 10.1.1.2.1 and 

10.1.1.2.2 of this appendix. For stack gas flow rate, diluent 

gas, and moisture monitoring systems, the monitoring plan shall 

include the electronic and hard copy information required for 

those systems under §75.53 (g) of this chapter. The electronic 

monitoring plan shall be evaluated using the ECMPS Client Tool.

10.1.1.2.1 Electronic. Record the unit or stack ID number(s); 

monitoring location(s); the HCl or HF monitoring methodology

used (i.e., CEMS); HCl or HF monitoring system information, 

including, but not limited to: unique system and component ID 

numbers; the make, model, and serial number of the monitoring 

equipment; the sample acquisition method; formulas used to 

calculate emissions; monitor span and range information (if 
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applicable).

10.1.1.2.2 Hard Copy. Keep records of the following: schematics 

and/or blueprints showing the location of the monitoring 

system(s) and test ports; data flow diagrams; test protocols; 

monitor span and range calculations (if applicable); 

miscellaneous technical justifications.

10.1.2 Operating Parameter Records. For the purposes of this 

appendix, the owner or operator shall record the following 

information for each operating hour of each affected unit or

group of units utilizing a common stack, to the extent that 

these data are needed to convert pollutant concentration data to 

the units of the emission standard. For non-operating hours, 

record only the items in paragraphs 10.1.2.1 and 10.1.2.2 of 

this section. If there is heat input to the unit(s), but no 

electrical load, record only the items in paragraphs 10.1.2.1, 

10.1.2.2, and (if applicable) 10.1.2.4 of this section.

10.1.2.1 The date and hour;

10.1.2.2 The unit or stack operating time (rounded up to the 

nearest fraction of an hour (in equal increments that can range 

from one hundredth to one quarter of an hour, at the option of 

the owner or operator);

10.1.2.3 The hourly gross unit load (rounded to nearest MWge);

and
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10.1.2.4 If applicable, the F-factor used to calculate the heat

input-based pollutant emission rate.

10.1.3 HCl and/or HF Emissions Records. For HCl and/or HF CEMS, 

the owner or operator must record the following information for 

each unit or stack operating hour:

10.1.3.1 The date and hour;

10.1.3.2 Monitoring system and component identification codes, 

as provided in the electronic monitoring plan, for each hour in 

which the CEMS provides a quality-assured value of HCl or HF

concentration (as applicable);

10.1.3.3 The pollutant concentration, for each hour in which a 

quality-assured value is obtained. For HCl and HF, record the 

data in parts per million (ppm), rounded to three significant 

figures. 

10.1.3.4 A special code, indicating whether or not a qualityassured HCl or HF concentration value is obtained for the hour. 

This code may be entered manually when a temporary like-kind 

replacement HCl or HF analyzer is used for reporting; and

10.1.3.5 Monitor data availability, as a percentage of unit or 

stack operating hours, calculated according to §75.32 of this 

chapter.

10.1.4 Stack Gas Volumetric Flow Rate Records.

10.1.4.1 Hourly measurements of stack gas volumetric flow rate 
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during unit operation are required to demonstrate compliance 

with electrical output-based HCl or HF emissions limits (i.e., 

lb/MWh or lb/GWh).

10.1.4.2 Use a flow rate monitor that meets the requirements of 

part 75 of this chapter to record the required data. You must 

keep hourly flow rate records, as specified in §75.57(c)(2) of 

this chapter.

10.1.5 Records of Stack Gas Moisture Content.

10.1.5.1 Correction of hourly pollutant concentration data for 

moisture is sometimes required when converting concentrations to 

the units of the applicable Hg emissions limit. In particular, 

these corrections are required:

10.1.5.1.1 To calculate electrical output-based pollutant 

emission rates, when using a CEMS that measures pollutant

concentrations on a dry basis; and

10.1.5.1.2 To calculate heat input-based pollutant emission 

rates, when using certain equations from EPA Method 19 in 

appendix A-7 to part 60 of this chapter.

10.1.5.2 If hourly moisture corrections are required, either use

a fuel-specific default moisture percentage for coal-fired units 

from §75.11(b)(1) of this chapter, an Administrator approved 

default moisture value for non-coal-fired units (as per 

paragraph 63.10010(d) of this subpart), or a certified moisture 
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monitoring system that meets the requirements of part 75 of this 

chapter, to record the required data. If you elect to use a 

moisture monitoring system, you must keep hourly records of the 

stack gas moisture content, as specified in §75.57(c)(3) of this 

chapter.

10.1.6 Records of Diluent Gas (CO2 or O2) Concentration.

10.1.6.1 To assess compliance with a heat input-based HCl or HF 

emission rate limit in units of lb/MMBtu, hourly measurements of 

CO2 or O2 concentration are required to convert pollutant 

concentrations to units of the standard.

10.1.6.2 If hourly measurements of diluent gas concentration are

needed, you must use a certified CO2 or O2 monitor that meets the 

requirements of part 75 of this chapter to record the required 

data. For all diluent gas monitors, you must keep hourly CO2 or 

O2 concentration records, as specified in §75.57(g) of this 

chapter.

10.1.7 HCl and HF Emission Rate Records. For applicable HCl and 

HF emission limits in units of lb/MMBtu, lb/MWh, or lb/GWh, 

record the following information for each affected unit or 

common stack:

10.1.7.1 The date and hour;

10.1.7.2 The hourly HCl and/or HF emissions rate (lb/MMBtu, 

lb/MWh, or lb/GWh, as applicable, rounded to three significant 
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figures), for each hour in which valid values of HCl or HF 

concentration and all other required parameters (stack gas 

volumetric flow rate, diluent gas concentration, electrical 

load, and moisture data, as applicable) are obtained for the 

hour;

10.1.7.3 An identification code for the formula used to derive 

the hourly HCl or HF emission rate from HCl or HF concentration, 

flow rate, electrical load, diluent gas concentration, and 

moisture data (as applicable); and

10.1.7.4 A code indicating that the HCl or HF emission rate was 

not calculated for the hour, if valid data for HCl or HF 

concentration and/or any of the other necessary parameters are 

not obtained for the hour. For the purposes of this appendix, 

the substitute data values required under part 75 of this 

chapter for diluent gas concentration, stack gas flow rate and 

moisture content are not considered to be valid data. 

10.1.8 Certification and Quality Assurance Test Records. 

For the HCl and/or HF CEMS used to provide data under this 

subpart at each affected unit (or group of units monitored at a 

common stack), record the following information for all required 

certification, recertification, diagnostic, and qualityassurance tests:

10.1.8.1 HCl and HF CEMS. 
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10.1.8.1.1 For all required daily calibrations (including 

calibration transfer standard tests) of the HCl or HF CEMS, 

record the test dates and times, reference values, monitor 

responses, and calculated calibration error values;

10.1.8.1.2 For gas audits of HCl or HF CEMS, record the date and 

time of each spiked and unspiked sample, the audit gas reference 

values and uncertainties. Keep records of all calculations and 

data analyses required under sections 9.1 and 12.1 of 

Performance Specification 15, and the results of those 

calculations and analyses. 

10.1.8.1.3 For each RATA of a HCl or HF CEMS, record the date 

and time of each test run, the reference method(s) used, and the 

reference method and HCl or HF CEMS values. Keep records of the 

data analyses and calculations used to determine the relative 

accuracy. 

10.1.8.2 Additional Monitoring Systems. For the stack gas flow 

rate, diluent gas, and moisture monitoring systems described in 

section 3.2 of this appendix, you must keep records of all 

certification, recertification, diagnostic, and on-going 

quality-assurance tests of these systems, as specified in 

§75.59(a) of this chapter.

11. Reporting Requirements

11.1 General Reporting Provisions. The owner or operator shall 
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comply with the following requirements for reporting HCl and/or 

HF emissions from each affected unit (or group of units 

monitored at a common stack):

11.1.1 Notifications, in accordance with paragraph 11.2 of this 

section;

11.1.2 Monitoring plan reporting, in accordance with paragraph 

11.3 of this section;

11.1.3 Certification, recertification, and QA test submittals, 

in accordance with paragraph 11.4 of this section; and

11.1.4 Electronic quarterly report submittals, in accordance 

with paragraph 11.5 of this section.

11.2 Notifications. The owner or operator shall provide 

notifications for each affected unit (or group of units 

monitored at a common stack) in accordance with §63.10030.

11.3 Monitoring Plan Reporting. For each affected unit (or group 

of units monitored at a common stack) using HCl and/or HF CEMS, 

the owner or operator shall make electronic and hard copy 

monitoring plan submittals as follows:

11.3.1 Submit the electronic and hard copy information in 

section 10.1.1.2 of this appendix pertaining to the HCl and/or 

HF monitoring systems at least 21 days prior to the applicable 

date in §63.9984. Also, if applicable, submit monitoring plan 

information pertaining to any required flow rate, diluent gas, 
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and/or moisture monitoring systems within that same time frame, 

if the required records are not already in place. 

11.3.2 Update the monitoring plan when required, as provided in 

paragraph 10.1.1.1 of this appendix. An electronic monitoring 

plan information update must be submitted either prior to or 

concurrent with the quarterly report for the calendar quarter in 

which the update is required.

11.3.3 All electronic monitoring plan submittals and updates 

shall be made to the Administrator using the ECMPS Client Tool. 

Hard copy portions of the monitoring plan shall be kept on 

record according to section 10.1 of this appendix.

11.4 Certification, Recertification, and Quality-Assurance Test 

Reporting Requirements. Except for daily QA tests (i.e.,

calibrations and flow monitor interference checks), which are 

included in each electronic quarterly emissions report, use the 

ECMPS Client Tool to submit the results of all required 

certification, recertification, quality-assurance, and 

diagnostic tests of the monitoring systems required under this 

appendix electronically, either prior to or concurrent with the 

relevant quarterly electronic emissions report. 

11.4.1 For daily calibrations (including calibration transfer 

standard tests), report the information in §75.59(a)(1) of this 

chapter, excluding paragraphs (a)(1)(ix) through (a)(1)(xi). 
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11.4.2 For each quarterly gas audit of a HCl or HF CEMS, report:

11.4.2.1 Facility ID information;

11.4.2.2 Monitoring system ID number;

11.4.2.3 Type of test (e.g., quarterly gas audit);

11.4.2.4 Reason for test;

11.4.2.5 Certified audit (spike) gas concentration value (ppm); 

11.4.2.6 Measured value of audit (spike) gas, including date and 

time of injection;

11.4.2.7 Calculated dilution ratio for audit (spike) gas;

11.4.2.8 Date and time of each spiked flue gas sample;

11.4.2.9 Date and time of each unspiked flue gas sample;

11.4.2.10 The measured values for each spiked gas and unspiked 

flue gas sample (ppm);

11.4.2.11 The mean values of the spiked and unspiked sample

concentrations and the expected value of the spiked 

concentration as specified in section 12.1 of Performance 

Specification 15 (ppm);

11.4.2.12 Bias at the spike level as calculated using equation 3 

in section 12.1 of Performance Specification 15; and

11.4.2.13 The correction factor (CF), calculated using equation 

6 in section 12.1 of Performance Specification 15.

11.4.3 For each RATA of a HCl or HF CEMS, report:

11.4.3.1 Facility ID information;
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11.4.3.2 Monitoring system ID number;

11.4.3.3 Type of test (i.e., initial or annual RATA);

11.4.3.4 Reason for test;

11.4.3.5 The reference method used;

11.4.3.6 Starting and ending date and time for each test run;

11.4.3.7 Units of measure;

11.4.3.8 The measured reference method and CEMS values for each 

test run, on a consistent moisture basis, in appropriate units 

of measure;

11.4.3.9 Flags to indicate which test runs were used in the 

calculations;

11.4.3.10 Arithmetic mean of the CEMS values, of the reference 

method values, and of their differences; 

11.4.3.11 Standard deviation, as specified in Equation 2-4 of 

Performance Specification 2 in appendix B to part 60 of this 

chapter; 

11.4.3.12 Confidence coefficient, as specified in Equation 2-5 

of Performance Specification 2 in appendix B to part 60 of this 

chapter; and

11.4.3.13 Relative accuracy calculated using Equation 2-6 of 

Performance Specification 2 in appendix B to part 60 of this 

chapter or, if applicable, according to the alternative 

procedure for low emitters described in section 3.1.2.2 of this 
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appendix. If applicable use a flag to indicate that the 

alternative RA specification for low emitters has been applied.

11.4.4 Reporting Requirements for Diluent Gas, Flow Rate, and 

Moisture Monitoring Systems. For the certification, 

recertification, diagnostic, and QA tests of stack gas flow 

rate, moisture, and diluent gas monitoring systems that are 

certified and quality-assured according to part 75 of this 

chapter, report the information in section 10.1.9.3 of this 

appendix.

11.5 Quarterly Reports.

11.5.1 Beginning with the report for the calendar quarter in 

which the initial compliance demonstration is completed or the 

calendar quarter containing the applicable date in §63.10005(g), 

(h), or (j) (whichever is earlier), the owner or operator of any 

affected unit shall use the ECMPS Client Tool to submit 

electronic quarterly reports to the Administrator, in an XML

format specified by the Administrator, for each affected unit 

(or group of units monitored at a common stack). 

11.5.2 The electronic reports must be submitted within 30 days 

following the end of each calendar quarter, except for units 

that have been placed in long-term cold storage.

11.5.3 Each electronic quarterly report shall include the 

following information:
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11.5.3.1 The date of report generation;

11.5.3.2 Facility identification information;

11.5.3.3 The information in sections 10.1.2 through 10.1.7 of 

this appendix, as applicable to the type(s) of monitoring 

system(s) used to measure the pollutant concentrations and other 

necessary parameters. 

11.5.3.4 The results of all daily calibrations (including 

calibration transfer standard tests) of the HCl or HF monitor as 

described in section 10.1.8.1.1 of this appendix; and

11.5.3.5 If applicable, the results of all daily flow monitor 

interference checks, in accordance with section 10.1.8.2 of this 

appendix.

11.5.4 Compliance Certification. Based on reasonable inquiry of 

those persons with primary responsibility for ensuring that all 

HCl and/or HF emissions from the affected unit(s) have been 

correctly and fully monitored, the owner or operator shall 

submit a compliance certification in support of each electronic 

quarterly emissions monitoring report. The compliance 

certification shall include a statement by a responsible 

official with that official’s name, title, and signature, 

certifying that, to the best of his or her knowledge, the report 

is true, accurate, and complete.