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DRAFT – DELIBERATIVE DOCUMENT – DO NOT CITE OR QUOTE

EO12866NESHAPMACT_NSPSforUtilitiesMATS2060_AP52Final20111104.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

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, 

DC 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. Summary of EPA’s Finding that it is Appropriate and Necessary 

to Regulate EGUs to Address Public Health and Environmental 

Hazards with Emissions of Hg and Non-mercury HAP from EGUs

B. Peer Review of the National-Scale Hg Risk Assessment 

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 Chromium and Nickel Emissions in the U.S. EGU 

Case Studies of Cancer and Non-Cancer Inhalation Risks for Nonmercury 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 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 HAP from 

EGUs

IV. Denial of Delisting Petition

V. Summary of this Final NESHAP

A. What is the source category regulated by this final rule?
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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 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. Notification, Recordkeeping and Reporting

I. 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 this final NSPS

X. Summary of Significant Changes Since Proposal

XI. Public Comments and Responses to the Proposed NSPS

XII. Impacts of These Final Rules

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 

Executive Order 13563, Improving Regulation and Regulatory 

Review

B. Paperwork Reduction Act
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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 

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 

establishments are classified according to the activity in which 

they are engaged.
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This table is not intended to be exhaustive but rather 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., 

would 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 63.9982. 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, 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 

rule is available only by filing a petition for review in the 
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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 can be raised during 

judicial review. This section also provides a mechanism for us 

to convene a proceeding for reconsideration, “[i]f the person 

raising an objection can demonstrate to EPA 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 this 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, DC 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, DC 

20004. Note, under CAA section 307(b)(2), the requirements 

established by this final rule may not be challenged separately 
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in any civil or criminal proceedings brought by EPA to enforce 

these requirements.

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

Consistent with the recently issued Executive Order (EO) 

13563, “Improving Regulation and Regulatory Review,” we have 

estimated the cost and benefits of the final rule. This rule 

will reduce emissions of HAP including Hg from the electric 

power industry. As a co-benefit, the emissions of certain fine 

particulate matter (PM2.5) precursors such as sulfur dioxide (SO2) 

will also decline. The EPA estimates that this final rule will 

yield annual monetized benefits (in 2007$) of between $37 to $91 

billion using a 3 percent discount rate and $33 to $82 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 $9.2 billion (2007$) and the annual quantified net 

benefits (the difference between benefits and costs) are $28 to 

$81 billion using 3 percent discount rate or $24 to $72 billion 

using a 7 percent discount rate.

The benefits outweigh costs by between 4 to 1 or 10 to 1 

depending on the benefit estimate and discount rate used. The 

co-benefits are substantially attributable to the 4,300 to 
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11,000 fewer PM2.5-related premature mortalities. There are some 

costs and important benefits that EPA could not monetize, such 

as those for the HAP being reduced by this final rule other than 

Hg. Upon considering these limitations and uncertainties, it 

remains clear that the benefits of 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

Total Monetized 

Benefitsb

$37 to $91 $33 to $82

Hg-related Benefitsc $0.004 to $0.006 $0.0005 to $0.00

1

PM2.5-related Cobenefitsb$37 to $90 $33 to $81

Climate-related CoBenefits$0.35 $0.35

Total Social Costsd $9.2 $9.2

Net Benefits $28 to $81 $24 to $72

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. 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 RIA 

we also report the monetized CO2 co-benefits using discount rates 

of 5 percent, 2.5 percent, and 3 percent (95th percentile).

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 
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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. Mercury benefits were calculated using the 

baseline from proposal. The difference in emissions reductions 

between proposal and final would not substantially affect the Hg 

benefits. 

c Based on an analysis of health effects due to recreational 

freshwater fish consumption.

d Total social costs are approximated by the compliance costs. 

This does not include monitoring or reporting costs, which are 

currently being revised.

For more information on how EPA is addressing EO 13563, see 

the EO discussion, later in the preamble.

II. Background Information on the NESHAP

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

Congress established a specific structure for determining 

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 from EGUs’ HAP emissions after imposition 

of CAA requirements, 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 

 

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 112(a)(8).
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how the Administrator decides whether to list EGUs for 

regulation under CAA section 112. See New Jersey, 517 F.3d at 

582 (“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 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.

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 HAP subject to 

this section” that the EPA determines are achievable taking into 

account certain statutory factors. See CAA section 112(d). 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 emissions 

limitation achieved by the best performing 12 percent of 

existing sources in the category (for which the Administrator 

 

2 US 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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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 

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 for 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.
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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 

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” (the Mercury Study). 

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

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 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 
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required evaluation, “a study to determine the threshold level 

of Hg exposure below which adverse human health effects are not 

expected to occur” (the 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, 

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) (the 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 
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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. NAS 

completed its study 5 years after the NIEHS Study, and 

considered additional information not earlier available to 

NIEHS. Because the NAS Study was issued after the NIEHS study, 

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 

112(n)(1) concerning utility HAP emissions, the Utility Study

and the Mercury Study,3 and completed both by 1998. Prior to 

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

external peer reviews of the document. The NIEHS completed the 

NIEHS Study in 1995,4 and the NAS completed the NAS Study in 

2000.5

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 

 

3 {Add Mercury Study citation information}

4 {Add NIEHS Study citation information}

5 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. Many of the peer-reviewed articles 

cited in this section are publications originally cited in the 

NAS report.
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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). 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 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 
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(“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 

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 rejected the argument that the EPA has the inherent 

authority to correct its mistakes, finding 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. 
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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 

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 

be accompanied by standards for existing sources). Id. at 583-

84. Thus, CAMR and the Section 112(n) Revision Rule 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 

 

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.

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 
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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

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 

 

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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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 requirements, testing requirements, 

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 

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

Administrator pursuant to the Resource Conservation and Recovery 

Act (RCRA), will be subject to standards issued pursuant to CAA 

section 129 (e.g., CISWI energy recovery units), 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-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. See CAA section 112(a)(8) 

(defining EGU).

Pursuant to the CAA, an EGU is “any 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 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 
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MWe ratings quoted in the final rule to be the original 

nameplate-rated 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 

megawatts (MW). Units under that size 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 IGCC units 

that burn gasified coal or petroleum coke 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 

 

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

of an EGU but combusts natural gas exclusively or natural gas in 

combination with another fossil fuel where the natural gas 

constitutes 90 percent or more of the average annual heat input 

during the any 3 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 not-withstanding 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. The definition of “fossil fuel-fired” will 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” will also establish the amount 

of fossil fuel combustion necessary to make a unit become 

“fossil fuel fired” and hence potentially subject to 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 startup using either natural gas or oil 

and may use these fuels (or coal) during normal operation for 

flame stabilization.

To be considered “capable of combusting” coal or oil, an 
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EGU would need to have fossil fuels allowed in their operating 

permits and the appropriate fuel handling facilities on-site or 

otherwise available(such as oil storage facilities or coal 

handling equipment, storage areas, belts, conveyers, or 

pulverizers). 

In addition, the EPA is finalizing in the definition of 

“fossil fuel-fired” that an EGU must fire coal or oil for more 

than 10.0 percent of the average annual heat input during any 3 

consecutive calendar-year period or for more than 15.0 percent 

of the annual heat input during any one calendar year 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 (e.g.) 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, with 

consideration of the definitions of “fossil fuel” and “fossil 

fuel-fired,” will 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 
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and flame stabilization purposes only (i.e., less than 10.0 

percent of the average annual heat input in any 3 consecutive 

calendar year-period or less than 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.

On the other hand, 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 MWe will be considered an EGU if the facility 

is fossil fuel-fired as that term is defined above, i.e., the 

unit must be capable of combusting sufficient coal or oil to 

generate 25 MWe from the fossil fuel alone and must provide for 

sale to any utility power distribution system electricity equal 

to more than one-third of their potential electric output 

capacity and greater than 25 MWe electrical output.

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 MWe). A unit subject to one of the Boiler NESHAP that 
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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 

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 the data 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
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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 

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 
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the case of qualifying cogeneration facilities which 

burn homogeneous waste for the production of electric 

energy and steam or other forms of useful energy (such 

as heat) which are used for industrial, commercial, 

heating or cooling purposes...”

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). U.S. EGUs are the largest or among the 

largest domestic emitters of many HAP, including metals and acid 

gases. In 2005, U.S. EGUs emitted 50 percent of total 

anthropogenic Hg emissions, 62 percent of total arsenic (As) 
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emissions, 39 percent of total cadmium (Cd) emissions, 22 

percent of total chromium (Cr) emissions, 82 percent of total 

hydrogen chloride (HCl) emissions, 62 percent of total hydrogen 

fluoride (HF) emissions, 28 percent of total nickel (Ni) 

emissions, and 83 percent of total selenium (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 Cr VI) and two as probable human carcinogens (Cd and 

Ni). We do not know the extent to which the adverse health 

effects described above occur in the populations surrounding 

coal- and oil-fired EGUs. However, to the extent the adverse 

effects do occur, this final rule will reduce emissions and 

subsequent exposures.

III. Appropriate and Necessary Finding

In the preamble to the proposed rule,11 the EPA articulated 

its rationale for a determination that it is appropriate and 

 

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

available at http://www.epa.gov/ttn/atw/nata2005/

11 76 FR 24986
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necessary to regulate emissions of mercury (Hg) and other 

Hazardous Air Pollutants (HAP) from U.S. EGUs, confirming the 

finding made in 2000.

As discussed fully in the preamble to the proposed rule, 

EPA interprets the Clean Air Act (CAA) to require the Agency to 

find it appropriate to regulate U.S. EGUs under section 112 if 

the Agency determines that the emissions of one or more HAP 

emitted from U.S. EGUs pose an identified or potential hazard to 

public health or the environment. The Agency must find it 

necessary to regulate EGUs under CAA section 112 if the 

imposition of other requirements of the CAA would not adequately 

address the identified or potential hazards to public health or 

the environment. Moreover, it may be necessary to regulate 

utilities under CAA section 112 for a number of other reasons, 

including, for example, that CAA section 112 standards will 

assure permanent reductions in EGU HAP emissions, which cannot 

be assured based on other requirements of the CAA. 

In this section, we describe revisions to the technical 

analyses that accompanied the proposed rule and the responses to 

public comments on legal, technical, and policy aspects of the 

finding. We first summarize the elements of the appropriate and 

necessary finding, as discussed in the preamble to the proposed 

rule. We then discuss the results of the peer reviews of our 
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national-scale mercury risk assessment (hereafter referred to as 

the Hg Risk TSD) and non-mercury HAP risk assessment. In this 

discussion, we describe the peer review processes, the charges 

provided to the peer review panels, the findings and 

recommendations from the peer review panels, and EPA’s responses 

to those peer reviews. We also summarize the results of 

revisions to the Hg Risk TSD and the case studies of non-mercury

HAP inhalation risks and compare these results to those reported 

in the preamble to the proposed rule.

In the next subsection, we summarize and respond to the 

major categories of comments on the legal, technical, and policy 

aspects of the appropriate and necessary finding. The first 

portion of the response to comments subsection addresses legal 

aspects of the appropriate and necessary finding. This 

subsection includes comments on the history of CAA section 

112(n)(1)(a), the definition and interpretation of the terms 

“appropriate” and “necessary”, regulation of all HAP, 

consideration of both health and environmental effects in making 

the appropriate finding, consideration of costs in making the 

appropriate finding, consideration of CAA requirements in making 

the necessary finding, listing of U.S. EGU under CAA section 

112, and the 2000 finding. 

The second portion of the response to comments subsection 
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addresses comments related to the new technical analyses confirm 

that HAP emissions from U.S. EGUs remain a hazard to public 

health. This includes comments on the inputs, methods, and 

assumptions used in Hg Risk TSD, the non-mercury inhalation risk 

case studies, and the assessment of excess local deposition due 

to U.S. EGU Hg emissions. Comments on the Hg risk analysis 

included comments on the modeling of Hg emissions (both global 

and U.S.) and deposition, the RfD for MeHg, fish tissue Hg 

concentrations, the assumed linear relationship between changes 

in Hg deposition and changes in fish tissue Hg concentrations, 

the behavior of subsistence fishing populations, and fish 

consumption rates. Comments on the non-mercury inhalation risk 

case studies included comments on non-mercury HAP emissions, 

modeling parameters, estimating Ni and Cr risk, and an 

alternative risk analysis. Comments on the assessment of excess 

local deposition addressed the definition of hotspots, evidence 

for local Hg deposition from U.S. EGU emissions, documentation 

of methods, and limitations of deposition modeling. We also 

received comments related to ecosystem impacts from HAP, focused 

on the adverse impact of acid gases on ecosystems.

Based on our review of the comments and our updated 

analyses in response to the peer reviews, we affirm that it is 

appropriate and necessary to regulate EGUs to address public 
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health and environmental hazards associated with emissions of Hg 

and non-mercury HAP from EGUs. The revised analyses for Hg and 

non-mercury risk, which fully addresses the advice we received 

from the peer reviews, confirm that emissions of both Hg and 

non-mercury HAP from U.S. EGUs are a hazard to public health. 

These results, along with the other elements of the finding, 

confirm that it remains appropriate and necessary to regulate 

EGUs under CAA section 112 and that such units are properly 

listed pursuant to CAA section 112(c).

A. Summary of EPA’s Finding that it is Appropriate and Necessary 

to Regulate EGUs to Address Public Health and Environmental 

Hazards Resulting from Emissions of Hg and Non-mercury Hazardous 

Air Pollutants (HAP) from EGUs

In the preamble to the proposed rule, we confirmed our 2000 

finding that it is appropriate to regulate emissions of Hg) and 

other HAP from EGUs because emissions of those pollutants pose 

hazards to public health and the environment, and EGUs are the 

largest or among the largest contributors of many of those HAP. 

We also confirmed that it is necessary to regulate EGUs under 

CAA section 112 for a variety of reasons, including that hazards 

to public health and the environment posed by HAP emissions from 

EGUs remain after imposition of the requirements of the CAA. Our 

confirmation of the 2000 finding was supported in part by 
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several new analyses of the hazards to public health posed by 

both Hg and non-mercury HAP.

In this section, we summarize the finding as reported in 

the preamble to the proposed rule. Specifically, we address the 

Agency’s determination that it is appropriate and necessary to 

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

extensive analyses summarized in the preamble to the proposed 

rule and documented in several Technical Support Documents12,13

confirmed that it remains appropriate and necessary today to 

regulate EGUs under CAA section 112. The analyses demonstrated 

that it is appropriate to regulate emissions from coal- and oilfired EGUs under CAA section 112 because: 1) Hg and non-mercury

HAP continue to pose a hazard to public health, and U.S. EGU 

emissions cause and/or contribute to this hazard; 2) Hg and some 

non-mercury HAP pose a hazard to the environment; 3) U.S. EGU 

emissions are still the largest domestic source of U.S. Hg, HCl, 

and HF emissions, and a significant source of other HAP 

emissions; 4) Hg emissions from individual EGUs leads to excess 

 

12 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. 

13 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.
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local deposition in areas directly surrounding those individual 

EGUs (not solely the result of regionally transported 

emissions), and would not be adequately addressed through 

reductions in regional levels of Hg emissions, requiring 

controls to be in place at all U.S. EGU sources that emit Hg; 5) 

Hg emissions from EGUs affect not only deposition, exposures, 

and risk today, but may contribute to future deposition, 

exposure and risk due to the processes of reemission of Hg that 

occur given the persistent nature of Hg in the environment and 

that Hg will remain part of the global burden of Hg; in fact, 

the delay in issuing Hg regulations under CAA section 112 has 

already resulted in several hundred additional tons of Hg being 

emitted to the environment, and 6) effective controls for Hg and 

non-mercury HAP are available for U.S. EGU sources.

The EPA concluded that Hg emissions from U.S. EGUs are a 

public health hazard today due to their contribution to Hg 

deposition that leads to potential MeHg exposures above the RfD. 

The EPA also concluded that Hg emissions from U.S. EGUs 

contribute to environmental concentrations of Hg that are 

harmful to wildlife and can affect production of important 

ecosystem services, including recreational hunting, fishing, and 

wildlife viewing. The EPA further concluded that non-mercury HAP 

emissions from U.S. EGU are a public health hazard because they 
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contribute to elevated cancer risks. Finally, the EPA concluded 

that HCl and HF emissions from U.S. EGUs contribute to 

acidification in sensitive ecosystems and, therefore, pose a 

risk of adverse effects on the environment. 

The analyses demonstrated that it is necessary to regulate 

emissions from coal- and oil-fired EGUs under CAA section 112 

because 1) Hg emissions from EGUs remaining in 2016 still pose a 

hazard to public health and the environment in the absence of 

regulations under CAA section 112 that would be required to be 

implemented at that time, 2) U.S. EGU emissions of Hg 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, 

3) EGUs are the largest source of Hg in the U.S. and thus 

contribute to the risk associated with exposure to MeHg, 4) we 

cannot be certain that the identified cancer risks attributable 

to EGUs will be addressed through imposition of the requirements 

of the CAA, 5)the environmental hazards posed by acidification 

will not be fully addressed through imposition of the CAA, 6) 

regulation under CAA section 112 is the only way to ensure that 

HAP emissions reductions that have been achieved since 2005 

remain permanent, 7) direct control of Hg emissions affecting 

U.S. deposition is only possible through regulation of U.S. 

emissions; we are unable to control global emissions directly. 
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1. Finding that Hg Emissions from U.S. EGUs Continue to Pose a 

Hazard to Public Health and the Environment.

In support of the finding that Hg emissions from U.S. EGUs 

are a hazard to public health, EPA assessed the Hg-related risk 

to populations with high consumption of self-caught freshwater 

fish, which is the population most likely to experience elevated 

risk from Hg emissions from U.S. EGUs. This Hg Risk TSD 

incorporated detailed emissions, air quality, exposure, and risk 

modeling, which provided estimates of the watersheds in which 

populations with high levels of fish consumption experience the 

potential for risk due to deposition of Hg. The Hg Risk TSD 

assessed the hazard to public health posed by Hg emissions from 

U.S. EGUs focused on comparisons of the RfD to exposures caused 

or contributed to by Hg emissions from U.S. EGUs. In the Hg risk 

assessment, almost all (98 percent) of the more than 2,400 

watersheds for which we identified fish tissue data, exceeded 

the RfD, above which there is the potential for an increased 

risk of adverse effects on human health. U.S. EGU-attributable 

deposition of Hg contributes to a large number of those 

watersheds in which total potential exposures to MeHg from all 

sources exceed the RfD and, thus, pose a hazard to public 

health. We focused on the watersheds (where U.S. EGUattributable deposition alone resulted in potential MeHg 
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exposures above the RfD, regardless of the additional deposition 

from other sources of Hg deposition, and where U.S. EGUattributable deposition contributed at least 5 percent of the 

total Hg deposition. This approach is likely to understate risk 

because any contribution of Hg to watersheds where potential 

exposures to MeHg exceed the RfD poses a public health hazard. 

Thus, because we found a large percentage of modeled watersheds 

with populations potentially at-risk even using this approach, 

we have confidence that emissions of Hg from U.S. EGUs are 

causing a hazard to public health, as there are additional 

watersheds where U.S. EGUs contribute to Hg risk at lower 

percent benchmarks.

In total, the Hg risk assessment found an estimated 28 

percent of modeled watersheds with populations with potentially 

at-risk from exposure to MeHg based on the contribution of U.S. 

EGUs. This total includes watersheds that are potentially atrisk either because U.S. EGU-attributable deposition is 

sufficient to cause potential exposures to exceed the RfD even 

excluding the deposition from other U.S. and non-U.S. sources, 

or because the U.S. EGU-attributable deposition contributes 

greater than 5 percent of total deposition and total exposure 

from all sources is greater than the RfD. 
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We found that, at the 99th percentile fish consumption level 

for subsistence fishers, 22 percent of sampled watersheds where 

total potential exposures to MeHg exceed the RfD received at 

least 5 percent of Hg deposition from U.S. EGUs. Although the 

most complete estimate of potential risk is based on total 

exposures to Hg, including deposition from U.S. EGU sources, 

U.S. non-EGU sources, and global sources, the deposition 

resulting from Hg emissions from U.S. EGUs is large enough in 

some watersheds that persons consuming contaminated fish would 

have exposures that exceed the RfD even without additional 

deposition from other sources. Based on these considerations, we 

found that at the 99th percentile fish consumption level for 

subsistence fishers, in 12 percent of the sampled watersheds, 

U.S. EGUs are responsible for deposition that causes the RfD to 

be exceeded, even excluding consideration of the additional 

deposition from other sources.

In addition, we highlighted in the preamble to the proposed 

rule that the estimate of modeled watersheds with populations 

potentially at-risk from U.S. EGU-attributable Hg deposition is 

likely understated because the data on fish tissue MeHg 

concentrations that we were able to identify for the Hg risk 

assessment was limited in some regions of the U.S., such as 

Pennsylvania, with very high U.S. EGU attributable Hg 
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deposition. Thus, it is possible that watersheds with 

potentially high MeHg exposures were excluded from the Hg Risk 

TSD. In addition, due to limitations in our models and available 

data, we did not estimate risks in near-coastal waters, and some 

of these waters, such as the Chesapeake Bay, could have 

substantial EGU-attributable Hg deposition.

Further, scientific studies have found strong evidence of 

adverse impacts on species of fish-eating birds with high birdwatching value, including loons, white ibis, and great snowy 

egrets. Studies have also shown adverse effects on insect-eating 

birds including many songbirds. Adverse effects in fish-eating 

mammals, such as mink and otter, include neurological responses 

(impaired escape and avoidance behavior) which can influence 

survival rates. Because EGUs contribute to Hg deposition in the 

U.S., we reasonably concluded that EGUs are contributing to the 

identified adverse environmental effects.

Mercury emitted into the atmosphere persists for years, and 

once deposited, can be reemitted into the atmosphere by a number 

of processes, including forest fires and melting of snow packs. 

As a result, Hg emitted today can have impacts for many years. 

In fact, Hg emitted by U.S. EGUs in the past, including over the 

last decade, is still affecting concentrations of Hg in fish 

today. Failing to control Hg emissions from U.S. EGU sources 
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will result in long-term environmental loadings of Hg, beyond 

those loadings caused by immediate deposition of Hg within the 

U.S. Although we are not able to quantify the impact of U.S. EGU 

emissions on the global pool of Hg, U.S. EGUs contribute to that

global pool. Controlling Hg emissions from U.S. EGUs helps to 

reduce the potential for environmental hazard from Hg now and in 

the future. 

In the preamble to the proposed rule, we concluded that all 

of these findings independently support a determination that it 

is appropriate to regulate Hg emissions from EGUs.

2. Finding that U.S. EGU Non-mercury HAP Emissions Continue to 

Pose a Hazard to Public Health and the Environment.

In addition to the Hg risk assessment, EPA also reported in 

the preamble to the proposed rule the results of 16 case studies 

of inhalation risks of cancer for U.S. EGUs for which we had 

2007 to 2009 emissions data (based on the 2010 ICR) and that we 

anticipated would have relatively higher emissions of nonmercury HAP compared to other U.S. EGUs. The results of that 

analysis showed that of the 16 facilities modeled, 4 facilities 

(3 coal-fired facilities and 1 oil-fired facility) have 

estimated risks of greater than one in 1 million14 for the most 

 

14 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 
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exposed individual. Given Congress’ determination that 

categories of sources which emit HAP resulting in a lifetime 

cancer risk greater than one in 1 million should not be removed 

from the CAA section 112(c) source category list and should 

continue to be regulated under CAA section 112, we concluded 

that risks above that level from U.S. EGUs represent a hazard to 

public health such that it is appropriate to regulate EGUs under 

CAA section 112.

Although our case studies did not identify significant 

chronic non-cancer risks from acid gas emissions from the 

specific EGUs assessed, the Administrator remains concerned 

about the potential for acid gas emissions to add to already 

high atmospheric levels of other chronic respiratory toxicants 

and to environmental loading and degradation due to 

acidification. Electric generating units emit over half of the 

nationwide emissions of HCl and HF, based on 2010 emissions 

estimates. Given that acidification affects many sensitive 

ecosystems across the country, it is appropriate to reduce 

emissions of this magnitude, which may aggravate acidification. 

The Administrator concluded that, in addition to the regulation 

of non-mercury HAP that cause elevated cancer risks, it is 

 

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.
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appropriate to regulate those HAP that are not known to cause 

cancer but are known to contribute to chronic non-cancer 

toxicity and environmental degradation, such as the acid gases. 

These findings independently supported the determination 

that it remains appropriate to regulate HAP emissions from EGUs.

3. Finding that Effective Controls are Available to Reduce Hg 

and Non-mercury HAP Emissions

Particle-bound Hg can be effectively removed along with 

other flue gas PM (including non-mercury metal HAP) in primary 

or secondary PM control devices. Electrostatic precipitators, 

fabric filters, and wet flue gas desulfurization (FGD) scrubbers 

are all effectively remove Hg; the degree of effectiveness 

depends on the specific characteristics of the EGU and fuel 

types. Additionally, these devices all effectively remove nonmercury metal HAP. Activated carbon injection is the most 

successfully demonstrated Hg-specific control technology. Acid 

gases are readily removed in typical FGD systems due to their 

solubility or their acidity (or both). The availability of 

controls for HAP emissions from EGUs supported the appropriate 

finding because sources will be able to reduce their emissions 

effectively and, thereby, reduce the hazards posed by HAP 

emissions from EGUs.
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4. The Administrator’s Finding that it Remains Necessary to 

Regulate Coal- and Oil-fired EGUs Under CAA Section 112

The EPA determined that, in 2016, the hazards posed to 

human health and the environment by HAP emissions from EGUs will 

not be addressed; therefore, it is necessary to regulate EGUs 

under CAA section 112. In addition, it is necessary to regulate 

EGUs under CAA section 112 because the only way to ensure 

permanent reductions in U.S. Electric generating unit emissions 

of HAP and the associated risks to public health and the 

environment is through standards set under CAA section 112.

The Agency first evaluated whether it is necessary to 

regulate HAP emissions from EGUs “after imposition of the 

requirements of the CAA.” As explained above, we interpret that 

phrase to require the Agency to consider only those requirements 

that Congress directly imposed on EGUs through the CAA as 

amended in 1990 and for which EPA could reasonably predict HAP 

emission reductions at the time of the Utility Study.15

Nonetheless, the Agency recognizes that it has discretion to 

look beyond the Utility Study in determining whether it is 

necessary to regulate EGUs under CAA section 112. Because 

several years have passed since the 2000 Finding, we conducted 

 

15 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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an additional, updated analysis, examining a broad array of 

diverse requirements.

Specifically, we analyzed HAP emissions from U.S. EGUs 

remaining in 2016. The baseline for our analysis included 

emission reductions anticipated from the proposed Transport Rule 

(finalized in June 2011 as the Cross-State Air Pollution 

Rule(CSAPR)16); CAA section 112(g); the Acid Rain Program; 

settlements of federal, state, and citizen enforcement actions 

related to criteria pollutant emissions from EGUs; and some 

state rules related to criteria pollutant emissions. We included 

state requirements and citizen and state enforcement action 

settlements associated with criteria pollutants because those 

requirements may have a basis under the CAA. However, we did not 

conduct an analysis to determine whether the state requirements 

are based on requirements of the CAA. As such, there may be 

instances where we should not have considered certain state 

 

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

appropriate and necessary finding, EPA has updated IPM modeling 

to reflect to the most recently available information, including 

public comments and 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. The current projection in 2016, there 

will be 27 tons of Hg emitted by U.S. EGU, as compared to the 29 

tons we modeled for the Hg Risk TSD. We do not expect that the 2 

tons less of Hg will substantially change the mercury risks that 

we reported in the preamble to the proposed rule, as this

represents less than a 10 percent reduction in Hg emissions. 
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rules or state and citizen suit enforcement settlements in our 

analysis, because those requirements may be based solely in 

state law and not be required by the CAA as contemplated under 

CAA section 112(n)(1)(A). To the extent that these non-federal 

actions do not result in permanent reductions in Hg emissions, 

their inclusion in the baseline Hg emissions estimates for the 

Hg Risk TSD would underestimate the risks associated with Hg 

emissions from U.S. EGUs. We did not include in our analysis any 

state-only requirements or voluntary actions to reduce HAP 

emissions because there is no Federal backstop for those 

requirements and actions.

Our analysis confirmed that Hg emissions from EGUs 

remaining in 2016 still pose a hazard to public health and the 

environment and, therefore, it remains necessary to regulate 

EGUs under CAA section 112. Specifically, we estimated that U.S. 

EGU emissions of Hg after imposition of the requirements of the 

CAA will be 29 tons per year in 2016, the same as the level of 

Hg that we estimated at the time of proposal would be emitted by 

U.S. EGUs today. As stated above, we evaluated the hazards to 

public health and the environment from Hg based on the estimated 

Hg emissions in 2016 and found that a hazard exists. Because a 

hazard remains after imposition of the requirements of the CAA, 

we determined it is necessary to regulate EGUs.
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It is necessary to regulate HAP emissions from EGUs, even 

though the hazards from Hg will not be fully resolved through 

regulation under section 112. The EPA concluded in the preamble 

to the proposed rule that incremental reductions in Hg are 

important because as exposure above the RfD increases, the 

likelihood and severity of adverse effects increases. 

In the preamble to the proposed rule, we also found that it 

is necessary to regulate EGUs under CAA section 112 based on 

non-mercury HAP emissions because we could not be certain that 

the identified cancer risks attributable to EGUs will be 

addressed through imposition of the requirements of the CAA. In 

addition, the environmental hazards posed by acidification would 

not be fully addressed through imposition of the CAA.

In the preamble to the proposed rule, we also found it 

necessary to regulate EGUs because regulation under CAA section 

112 is the only way to ensure that HAP emissions reductions that 

have been achieved since 2005 remain permanent. Real reductions 

between 2005 and 2010 are attributable to state Hg regulations 

and to the Clean Air Interstate Rule (CAIR) and Federal 

enforcement actions that achieve Hg reductions as a co-benefit 

of controls for PM, NOX, and SO2 emissions. However, there are no 

national, federally-binding regulations for Hg. State Hg 

regulations can potentially change or be revoked without EPA 
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approval, and reductions that occur as a co-benefit of criteria 

pollutant regulations can also change. Furthermore, companies 

can change their criteria pollutant compliance strategies and 

use methodologies that do not achieve the same level of Hg or 

other HAP co-benefit (e.g., purchasing allowances in a trading 

program instead of using add-on controls).

As with Hg, the most recent data on HCl and HF emissions 

U.S. EGUs show a significant reduction between 2005 and 2010. 

These reductions in HCl and HF are the co-benefit of controls 

installed to meet other CAA requirements, including enforcement 

actions, and to a lesser extent, state regulations. There is no 

guarantee other than regulation under CAA section 112 that these 

significant decreases in HCl and HF emissions will be permanent. 

Although we do not have estimates for the remaining HAP emitted 

from U.S. EGUs, it is likely that such emissions have also 

decreased between 2005 and 2010. Thus, the Administrator found 

it necessary to regulate HAP emissions from U.S. EGUs to ensure 

that HAP emissions reductions are permanent.

Finally, direct control of Hg emissions affecting U.S. 

deposition is only possible through regulation of U.S. 

emissions; we are unable to control global emissions directly. 

Although the U.S. is actively involved in international efforts 

to reduce Hg pollution, the ability of the U.S. to argue 
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effectively in these negotiations for strong international 

policies to reduce Hg air emissions depends in large part on our 

domestic policies, programs and regulations to control Hg.

All of these findings independently supported the finding 

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

112.

Therefore, given the Agency’s finding that it remains 

appropriate and necessary to regulate coal- and oil-fired EGUs 

under CAA section 112, the EPA confirmed in the preamble to the 

proposed rule its decision to include coal- and oil-fired EGUs 

on the list of source categories regulated under CAA section 

112(c).

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, 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-mercury HAP from EGUs, 

EPA determined that the Hg Risk TSD supporting EPA’s 2011 review 

of U.S. EGU health impacts should be peer-reviewed.”

17 We also 

indicated that due to the court-ordered schedule for the final 

rule, we would conduct the peer review as expeditiously as 

 

17 76 FR 25012
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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.

We have completed the peer review of the Hg Risk TSD, which 

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 routine 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, EPA conducted a peer review in accordance with OMB’s 

Final Information Quality Bulletin for Peer Review19 as described 

 

18 U.S. EPA, 2011a.

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

Quality Bulletin for Peer Review. December. Available on the 
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below. All the materials related to the peer review, including 

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

rulemaking. 

The EPA commissioned the peer review through EPA’s Science 

Advisory Board (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 

 

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

03. 

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 
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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. 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. 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 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 

 

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

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

22 76 FR 29746

23 76 FR 39102

24 76 FR 50729

25 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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website and were added to the docket for the final rule on 

October 14, 2011.26

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 

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 

 

26 See 

http://yosemite.epa.gov/sab/sabpeople.nsf/WebCommittees/BOARD
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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 

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 
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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 

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 
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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. 

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 
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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 

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 
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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 

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 
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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 

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 

 

27 U.S. EPA-SAB, 2011.

28 Id.

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

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

EPA’s response to these recommendations.

4. EPA Responses to Peer Review Recommendations

In response to the peer review, EPA has substantially 

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

of the recommendations from the SAB peer review panel and 

includes a detailed list 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, 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 
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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 

structure of the Revised Hg Risk TSD accordingly.

 Clarify the rationale for using an 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. 

Reflecting precedent in interpreting HQ estimates, we 

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

one) represent a potential public health hazard.

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 

 

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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of 1. Thus, exposures at or above 1.5 are considered above 

the RfD and represent a potential public health hazard.

 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 

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 

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 

 

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, DC. EPA 823-B-00-007.

32 In the March Hg Risk TSD, 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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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 

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. This 

additional data expanded the number of watersheds in the 

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

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 
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exposures, from 29 percent in the revised Hg Risk TSD to 26 

percent in the sensitivity analysis in the 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 
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caught” or “as prepared.” We carefully reviewed the studies 

underlying the fish consumption rates used in the Hg Risk 

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 
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generally supportive of the approach used for identifying 

watersheds with the potential for subsistence activity, 

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 

 

33 In the Revised Mercury Risk TSD, this population is also 

referred to as the “typical female subsistence consumer.”
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watersheds with a population of at least 25 low-income 

females. The female subsistence fishing scenario provides 

greater coverage geographically than the high-consuming 

low-income female scenario.

 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 

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 
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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 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 emissions. We found that the estimates of 

the percent of modeled watersheds with populations 

potentially 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 
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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. We do not believe that the aspects of 

variability assessed qualitatively in the Hg Risk TSD such 

as temporal response in fish tissue would substantially 

change the risk results given the stated goal of the 

analysis.

 Additional sources of uncertainty should be discussed in 
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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 

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 
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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, but 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 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 
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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 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, and 8) evaluated 

the potential impact of the uncertainty in application of 

the RfD to low SES populations, and determined that due to 

the method used in calculating the RfD, have confidence 
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that the RfD may coverage 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 only a small decrease in the 

estimates of risk.

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 
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fish samples that meet the filtering criteria34 in representing 

potential risks for low income female subsistence fishing 

populations. Based on these revisions, our estimates of the 

number and percent of modeled watersheds with populations 

potentially at-risk from exposure to EGU-attributable MeHg 

changed from those presented in the preamble to the proposed 

rule. For the 99th 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 percent of modeled watersheds with 

populations potentially at-risk increased from 28 percent to 29 

percent. For the 95th percentile consumption scenario, the 

percent of modeled watersheds with populations potentially atrisk has increased from 22 percent to 24 percent. The increase 

in the percent of modeled watersheds with populations 

potentially at-risk using the expanded geographic coverage of 

watersheds provides additional confidence that emissions of Hg 

from U.S. EGUs are a hazard to public health.

The additional sensitivity analyses conducted in response 

 

34 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.
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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 sources35 resulted in an increase in 

the percent of modeled watersheds with populations potentially 

at-risk, from 29 percent to 33 percent. Including only 

watersheds in the top 25th percentile of U.S. EGU deposition 

resulted in an increase in the percent of modeled watersheds 

with populations potentially at-risk, from 29 percent to 30 

percent. Using the 50th percentile fish tissue Hg level resulted 

in a decrease in the percent of modeled watersheds with 

populations potentially at-risk, 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 are a hazard to public health. In fact, 

given the broader coverage of modeled watersheds in the revised 

 

35 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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analysis, we have greater confidence in our finding that U.S. 

EGU Hg emissions result in deposition that causes 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-mercury HAP 

and EPA Response

As explained in the preamble to the proposed rule, EPA 

determined to peer review its characterization of the chemical 

speciation for the emissions of Cr and Ni used in the nonmercury HAP inhalation risk case studies. The Agency determined 

that the remaining aspects of the non-mercury HAP case study 

risk assessments used methods that were already been subject to 

adequate peer review. The methodologies used to conduct those 

risk assessments were consistent with those used to conduct 

inhalation risk assessments under EPA’s Risk and Technology 

Review (RTR) program. Because the RTR assessments are 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 2010.36 The 

 

36 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 
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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, 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

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 

 

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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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. 

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., 
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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)), EPA has provided several 

approaches37 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 

 

37 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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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 

consideration; 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 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 
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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. EPA 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. 38

a. Cr and Cr compounds:

In agreement with the peer reviewers and based on the 

health effects information available for Cr, 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, EPA considers derivation of default speciation 

profiles based on the mass of Cr(VI) a reasonable approach. As 

suggested by one of the reviewers, EPA reviewed two potentially 

relevant studies, one of which showed coal combustion emissions 

containing as much as 43 percent Cr(VI),

39 which suggests that 

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., three to five percent of 

 

38 U.S. EPA, 2011c.

39 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.
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total Cr, which was close to limit of detection in this study).40

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, 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 

to risk characterization of Ni compounds, EPA considers all Ni 

compounds to be carcinogenic as a group and, contrary to the 

point of view expressed by representatives of oil-fired EGUS, 

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 

 

40 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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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 NTP rodent bioassay (which is different from the 

positive 2-year NTP bioassay for Ni subsulfide).41,42,43 One review 

article identifies 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, EPA identified 

 

41 Oller A. 2002. “Respiratory carcinogenicity assessment of 

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

42 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.

43 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.
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a recent review44 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 TCEQ45 for all 

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

Integrated Risk Information System (IRIS, 1991)46 specifically 

for Ni subsulfide. The third reviewer did not comment on an 

alternative approach. Considering this, 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 

 

44 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.

45 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

46 U.S. EPA, 1991. Integrated Risk Information Service (IRIS) 

assessment for nickel subsulfide. Available at: 

http://www.epa.gov/iris/subst/0273.htm.
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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, 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.

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.47,48

 

47 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.

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

Series No. 454, Toxicology and carcinogenesis studies of nickel 

sulfate hexahydrate. July. Available online at 
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E. Summary of Results of Revised U.S. EGU Case Studies of Cancer 

and Non-Cancer Inhalation Risks for Non-mercury HAP 

Based on the results of the peer review and public comments 

on the non-mercury 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 Niassociated inhalation 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 sixteen 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 million (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 

 

http://ntp.niehs.nih.gov/ntp/htdocs/LT_rpts/tr454.pdf.
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Ni. 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) values less than one, with a maximum TOSHI value 

of 0.4 (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 may 

underestimate true maximum risks for the source category.

Based on the fact that six 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 EPA’s 2000 
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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 

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 
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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.

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 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). The EPA clearly articulated 

its basis for listing EGUs in this proposed rule, which is 
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consistent with CAA section 307(d), and the commenter was 

provided an ample opportunity to comment. Third, the commenter 

asserts that the rulemaking 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-HQ-OAR-2009-0234-3056. 

Comment: One commenter stated that EPA has assessed the public 

health risks posed by HAP emissions from coal- and oil-fired 

EGUs for the last 40 years. According to the commenter, 

throughout that time, 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, 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, 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, EPA’s newfound concern about 

HAP emissions from EGUs is not based on new and different 
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assessments of the public health consequences of EGU HAP 

emissions but instead on health benefits from the reduction of 

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, 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, 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, EPA added coal- and 
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oil-fired EGUs to the CAA section 112(c) list of source 

categories for which emission standards are to be established 

pursuant to CAA section 112(d). Further, in support of the 

proposed rule published in the Federal Register on May 3, 2011, 

EPA conducted additional extensive quantitative 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 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 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 simply lacks foundation. The proposal unmistakably 

focuses on the hazards to public health associated with HAP 

emissions from EGUs.
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Comment: One commenter stated that CAA section 112 required EPA 

to make a risk-based determination in order to regulate HAP. 

According to the commenter, 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, EPA has regulated a number of HAP emitted from 

industrial source categories other than EGUs. 

As for EGUs, according to the commenter, 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 EPA, 

in past reviews, found that these HAP emissions did not pose 

hazards to public health. See 48 FR 15076, 15085 (1983) 

(radionuclides). In the case of Hg specifically, 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).
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In the late 1980s, the EPA was concerned that its prior 

risk assessments of individual HAP emissions from fossil-fuelfired power plants may not reflect the total risks posed by all 

HAP emitted by those sources. 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. As the commenter notes, 

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 
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section 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 were 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 EPA could or 

should rely on assessments of Hg from EGUs conducted prior to 

the 1990 amendments is not tenable. 

Finally, one commenter stated that 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 
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margin of safety” test. The commenter did not cite the study or 

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, 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 at 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, 

EPA did not provide in 2000 any interpretation of what it now 

characterizes as the “critical terms” of section 112(n)(1). See, 
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e.g., 70 FR at 15999 n.13 (the “2000 finding does not provide an 

interpretation of the phrase ‘after imposition of the 

requirements of the Act’”); id. at 16000/2 (in 2000, EPA “did 

not provide an interpretation of the term ‘appropriate’”); 76 FR 

at 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...”

49

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 

 

49 Id. at 24,977/3.
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regulatory terms at issue, it discussed the types of 

considerations relevant to the A and N inquiry. For example, it 

is clear that 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 112.50

In addition, when evaluating whether it was necessary to 

regulate utilities, the Agency 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. If anything, making an 

interpretation in 2005 that directly contradicted a prior 

factual conclusion was improper. At least one commenter who 

takes issue with the interpretation in the preamble to the 

proposed rule participated in the 2005 action and it did not 

complain at that time about the Agency establishing an express 

 

50 65 FR 79830.
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interpretation that obviously was in conflict with a prior 

Finding. In any case, the commenter has provided no legal 

support for its position that the Agency erred in interpreting 

the statute in a manner that is consistent with a prior factual 

finding. 

Comment: Several commenters stated that a finding that HAP 

regulation is “appropriate” for a single HAP does not indicate 

that it is “appropriate” to regulate all HAP. According to the 

commenters the sponsor of the House bill that became section 

112(n)(1)(A) provides an explanation that contradicts EPA’s 

approach. ”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 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).
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The commenters stated that 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 commenter maintains that the Agency’s 

interpretation of CAA section 112(n)(1) is flawed in many 

respects. The primary support for 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 

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., 
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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...”).51 As these cases show, the Supreme 

 

51 The D.C. Circuit has similarly refused to rely on such limited 

legislative history, as evidenced by NRDC v. EPA in which that 

Court stated:

It is true...that we ‘may examine the statute’s legislative 

history in order to “shed new light on congressional 

intent, notwithstanding statutory language that appears 

superficially clear.”‘“ Consumer Elecs. Ass’n v. FCC, 358 

U.S. App. D.C. 180, 347 F.3d 291, 298 (D.C. Cir. 2003)

(quoting NRA of Am., Inc. v. Reno, 342 U.S. App. D.C. 231, 
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Court does not give any 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 any 

reliance on such limited legislative history. 

We could not find, and 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, 

 

216 F.3d 122, 127 (D.C. Cir. 2000) (quoting Natural Res. 

Def. Council, Inc. v. Browner, 313 U.S. App. D.C. 37, 57 

F.3d 1122, 1127 (D.C. Cir. 1995))). But “‘the bar is 

high,’” id. (quoting Williams Cos. v. FERC, 358 U.S. App. 

D.C. 109, 345 F.3d 910, 914 (D.C. Cir. 2003)), and “only 

rarely have we relied on legislative history to constrict 

the otherwise broad application of a statute indicated by 

its text,” id. Here, EPA cannot clear the high bar relying 

solely on the isolated remarks of a few senators. Cf. Davis 

County Solid Waste Mgmt. v. EPA, 322 U.S. App. D.C. 107, 

101 F.3d 1395, 1407 (D.C. Cir. 1996) (finding contradictory 

comments of individual [**23] senators during section 129 

debates “too ‘meager [a] record’” to rely on “‘given the 

clear statutory language’ to the contrary”) (quoting Engine 

Mfrs. Ass’n v. EPA, 319 U.S. App. D.C. 12, 88 F.3d 1075, 

1091 (D.C. Cir. 1996)). In any event, the remarks that EPA 

cites, when viewed in the context of the express and

unambiguous provisions in the statute, show only that when 

the Congress wanted to exempt a particular kind of solid 

waste combustor from section 129’s coverage--based on the 

desirability of resource recovery or any other interest--it 

knew how to accomplish this through an express statutory 

exception and in fact did so for four specific classes of 

combustion units. See 42 USC section 7429(g)(1)

489 F.3d 1250, 1259 (D.C. Cir. 2007).
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or Committee Reports that supports Oxley’s statement. The lack 

of support for Oxley’s statement in the Committee Report 

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.”

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: “[t]he 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 
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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.”

Senator Durenberger also explained why the House version 

was adopted: “[g]iven 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.”

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, EPA reasonably 

declined to consider (or even discuss) the legislative history 

in the preamble to the proposed rule and we believe it would be 
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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 

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.52

 

52 In addition, 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 
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Our interpretation, not commenters’, should be afforded 

deference because the legislative history the commenters rely on 

is not controlling. In addition, commenters often cite 

Representative Oxley’s statements as support for alternative 

interpretations of CAA section 112(n)(1). We believe that any 

arguments that rely such limited legislative history are without 

merit. 

Comment: One commenter stated that 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 at 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 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 

 

review of existing State and industry control standards, 

techniques and enforcement.”).
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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.

According to the commenter, it is not enough that 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 

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 
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itself, as interpreted after considering the statements of 

Representative Oxley.

Response: The commenter appears to argue that EPA’s 

interpretation of CAA section 112(n)(1) is not consistent with 

the plain language of the statute, implying that the statute is 

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 flawed legislative history 

discussed above. As explained in the preamble to the proposed 

rule, the statute is subject to multiple interpretations, and we 

provided a reasoned basis for all the changes made to the 2005 

interpretation. 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 deference pursuant to National Cable & 

Telecommunication Ass’n v. Brand X Internet Services, 545 U.S. 

967 (2005). 
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Comment: One commenter asserts that 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, 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 at 

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 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, 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 
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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, 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 healthrelated benefits EPA quantifies is Hg. Elsewhere, the commenter 

stated that 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 at 24999/2. With 

respect to Hg the commenter stated that the benefits are so 

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 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 
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to HAP regulation itself. The commenter concludes that EPA 

distorts CAA section 112(n)(1)(A) “beyond all recognition.”

One commenter stated that 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, 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, EPA 

has seized upon the fact that the 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 
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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. PM benefits are only 

discussed in the Regulatory Impact Analysis accompanying the 

rule

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 the benefits associated with reductions of 

HAP emissions from EGUs or because the benefits that are 

quantified are small in relation to the co-benefits achieved 

through reductions in non-HAP air pollutants. What the commenter 

omits is the fact that the Agency is not required to quantify 

any benefits under the CAA before regulating HAP emissions from 

EGUs. The statute does not require any consideration of costs or 

benefits and the commenter has not shown that such 

considerations are required under CAA section 112. As explained 
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below, EPA does not consider costs when determining whether to 

regulate EGUs under CAA section 112.

Comment: One commenter stated that 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 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 
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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 which Congress did choose to apply to other source 

categories. The commenter stated that 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.

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 EPA recognized 

“that it had to address” the legislative history in its 2005 

action, and that 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, 

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 what then 

commenter fails to recognize now, that the Agency cannot argue 
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that the meaning of CAA section 112(n)(1)(A) is clear based on 

the statements of one legislator. 

The commenter is incorrect when it asserts that EPA’s 

opinion is of no moment. The Agency tasked with implementing an 

ambiguous statute is given considerable deference in 

interpreting the provision. The commenter’s assertion that 

Congress unambiguously defined the factors to consider in making 

the appropriate determination is wholly without merit. We 

explain in the preamble to the proposed rule the basis for the 

Agency’s interpretation, and we are not revising that 

interpretation based on the comments received.

c. Consideration of Both Public Health and Environmental Effects

Comment: Several commenters stated that 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 

regulation of EGUs is to be predicated solely on “hazards to 

public health” attributable to HAP emissions. The legislative 

history providing that 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. 
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The commenter further stated that nothing on the face of CAA 

section 112(n)(1)(A) indicates that Congress intended that 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 Study53 and 

the NAS Study54). 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.

Response: The commenter again relies 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 paltry evidence, we need not address them as we have 

explained above. As we stated above, CAA section 112(n)(1) is an 

ambiguous statutory provision; thus, EPA’s interpretation, not 

commenter’s, is entitled to considerable deference because it is 

a reasonable reading of the statute. Chevron, 467 U.S. at 843-

44. The Agency directs attention to section III.A. of the 

proposed rule for responses to commenter’s arguments as we are 

not revising our interpretation.

 

53 U.S. EPA. 1997. Mercury Study Report to Congress. EPA–452/R–

97–003. December.

54 NAS, 2000.
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The commenter appears to maintain that EPA must interpret 

the scope of the appropriate and necessary finding 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 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)55; see also 76 FR 

 

55 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. 
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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.”

56 The commenter 

has provided little more than 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 attributable to 

EGUs. 

 

56 76 FR 24986-87.
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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 requires 

consideration of adverse environmental effect, and all of the 

other provisions of CAA section 112 that specifically require 

consideration of environmental effects have purposes that are 

distinguishable from CAA section 112(n)(1). Furthermore, the 

lack of a requirement to consider environmental effects in CAA 

section 112(n)(1) does not equate to a prohibition on the 

consideration of environmental effects as the commenter 

concludes. The EPA maintains that it 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 
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sources is harmed, irrespective of whether HAP emissions from 

EGUs alone would cause the harm.”

57

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, the commenter maintains that the Agency 

could regulate HAP emissions from EGUs under CAA section 112(n). 

Accordingly, to the extent that 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), EPA 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 commenter’s assertion that 

Congress intended EPA to regulate only those EGU HAP emissions 

 

57 76 FR 24988.
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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 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 

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).58

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 

 

58 76 FR 24989.
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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 has not provided an 

alternative theory for regulating EGUs under CAA section 112, 

other than to state that EPA could regulate under CAA section 

112(n)(1), and we have been unable to identify one absent clear 

statutory direction. However, even if we were to determine that 

we could issue standards pursuant to CAA section 112(n)(1), or 

some other alternative, we would decline to do so for several 

reasons. First, CAA section 112(n)(1) provides no guidance on 

how to establish standards and any 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. Second, 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. Finally, 
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we do not believe that Congress intended to treat EGUs 

differently from other source categories for purposes of 

establishing standards once they are listed.59

e. Considering Cost in Finding

Comment: 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.” The 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”

 

59 Congress defined EGUs is section 112(a)(8). That definition 

defines the EGU source category and it includes both major and 

area sources. 
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for a given public health objective without consideration of 

cost.

Response: The commenters first take issue with EPA’s explanation 

of why the Agency determined that costs should not be considered 

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. For this reason alone, it is reasonable to make the 

listing decision, including the appropriate determination, 

without considering costs. Congress could easily have required 

the Agency to consider costs, and, because it did not, 

commenter’s assertion that the Agency’s decision not to consider 

costs does not withstand scrutiny are unfounded. 

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. 
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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 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 our 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 regulations HAP emissions from stationary sources, 
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including EGUs. Section 112 of the CAA is “suitable [and] proper 

in the circumstances” because EPA has identified a hazard to 

public health and the environment 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.

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, EPA did not consider the costs of the 

alternative controls in the Utility Study, as implied by the 

commenter. In a footnote, the commenter attempts to refute EPA’s 

statement in the preamble to the proposed rule that EPA did not 

consider costs in the 2000 Finding by pointing to the only two 

mentions of cost in that notice. However, 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”
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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 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. 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 EPA is 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.
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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 unfounded. 

On the facts, 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.60 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 NSPS for EGUs and 

revised NAAQS. With regard to the latter, 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 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-

 

60 76 FR 24990.
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benefit HAP reductions attributable to all future CAA 

requirements. 

In the preamble to the proposed rule, EPA recognized that 

we could consider requirements beyond those considered in the 

Utility Study, and we did consider a number of requirements that 

far exceed what Congress contemplated when enacting CAA section 

112(n)(1)(A). 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 the requirements of the Act as explained in the 

preamble to the proposed rule.61 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. 

With regard to the legislative history, as stated above, 

Representative Oxley’s supposedly authoritative statement is not 

even consistent with the express terms of CAA section 

112(n)(1)(A) on this issue, and commenter here relies on that 

misstatement as support for its attack on the Agency’s 

reasonable interpretation of the statute. Specifically, 

Representative Oxley stated that EPA was to take “into account 

 

61 76 FR 24990.
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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) directed the Agency to 

consider only “imposition of the requirements of [the CAA].” We 

need not address this argument further. 

Finally, 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 cobenefit 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, 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, 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 
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“‘achieve a particular end.’” 76 FR at 24990, quoting Cellular 

Telecommunications v. FCC, 330 F.3d 502, 510 (D.C. Cir. 2003). 

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.

Response: The commenter again relies on the legislative 

statements of one Representative and asserts that the statements 

are controlling. It is commenter’s legal analysis that is 

flawed, not EPA’s interpretation of the statute. 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.

Further, the commenter appears to argue 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. The EPA reasonably interprets 
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the statute to authorize the Agency to find that it is necessary 

to regulate if we are unable to determine that imposition of the 

requirements of the Act will address identified hazards to 

public health and the environment. The statute does not prohibit 

this interpretation and it is a legitimate exercise of our 

discretion to err on the side of regulation in the face of 

uncertainty concerning the level of protection necessary to 

protect public health and the environment. This is particularly 

true in a determination such as the necessary finding that is 

based on modeled projections of emissions four years into the 

future. 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).

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 
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but, more importantly, the supposed standard that 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 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, 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 

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 
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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 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 1990 CAA amendments, all of which have been 

implemented and still hazards to public health and the 

environment still remain.

Finally, the commenter does not address all of the bases on 

which the necessary finding is made. Specifically, EPA found in 

the preamble to the proposed rule that it was necessary to 

regulate HAP emissions from EGUs because the hazards to public 
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health and the environment would not be addressed through 

imposition of the requirements of the Act. 

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 – and the Agency 

has not done so – 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-onarrival. According to the commenter, 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 at 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 
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in the same manner as other categories for which the statute 

requires regulation.” Id. (emphasis added). The commenter 

asserts that as EPA sees it, 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, 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 at 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, EPA presumes, CAA section 112(d). Id. The commenter 

stated that elsewhere, 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 
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says nothing about delisting EGUs.” See 76 FR at 24981/2, 

quoting 517 F.2d at 582.

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 
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establishing a MACT standard for EGUs under CAA section 112(d) 

is not what Congress had in mind at all.

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 regulated in the same manner as 

other categories for which the statute requires regulation. See 

76 FR 24993.
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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. It is equally true 

that Congress could have directed EPA to regulate HAP emissions 

from EGUs under subparagraph 112(n)(1)(A) if that is what it 

wanted, but it did not. 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 and the environment with an ample margin of 

safety). It is fully consistent with the plain language of CAA 

section 112(n)(1)(A) to conclude that EPA should list EGUs once 

the prerequisite appropriate and necessary finding is made, and 
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listed sources must be regulated under CAA section 112(d). See

CAA section 112(c)(2). 

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 

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 
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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). An argument could be made, therefore, that the 

CAA accords EPA with the discretion to regulate EGUs using 

strategies other than emission standards in CAA section 112(d). 

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), 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 

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 
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establish a “Beyond-the-Floor” 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 alternative control 

strategies for regulating HAP emissions from EGUs that may 

warrant regulation in the Utility Study, but the commenters’

interpretation of and 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, 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, 
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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, EPA obviously interpreted the statutory direction as a 

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 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. Further, our interpretation 

is consistent with the direction in CAA section 112(n)(1)(A) to 

develop the control strategies for HAP “emissions which may 

warrant regulation under this section.” Thus, the statute only 

directed the Agency to develop alternative control strategies 

for the HAP the Agency determined may warrant regulation under 

CAA section 112, and, tellingly, the Agency developed 

alternative control strategies for all different types of HAP 

emitted from U.S. EGUs. The commenters’ interpretation finds no 

support under the statute and we reject it. 
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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 

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.

Comment: One commenter does not agree with 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 
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the Agency must regulate EGUs,” were EPA to “find[] it 

appropriate and necessary to do so.” See 76 FR at 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 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 EPA is directed 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).

Response: The commenter makes a number of arguments that appear 

to take issue with 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 
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necessary. The commenter implies that EPA erred because 

alternative mechanisms for regulation of EGUs under CAA section 

112 might exist. We do not agree.

The commenter’s argument that 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 

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 if regulation is 

appropriate). For these reasons, we disagree that any error 

occurred because we did not specifically discuss in this 
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proposed rule whether we could or should regulate EGUs under CAA 

section 112(n)(1) instead of CAA section 112(d). 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 prior to the listing, we would 

still list and regulate 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. Even 

if CAA ection 112(n)(1) were available to regulate EGUs, there 

is sufficient uncertainty about the legally vulnerability of 

such an approach to caution against employing it. This is 

particularly true given that we have identified hazards to 

public health and the environment from HAP emissions from EGUs 

that warrant regulation. 

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 at 24993. The commenter 

appears to make much of our use of the word “must” in that 
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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 wrong on both 

points. In regard to commenter’s concern with the use of the 

word “must” in the sentence quoted above, we note that in the 

next sentence we stated that “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.” 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 - a point that undermines 

commenter’s argument that EPA should not regulate EGUs under CAA 

section 112(d). 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 best 

reading of the statute is the one we provided in the preamble to 

the proposed rule.

The commenter also stated that 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 EPA’s statements 

out of context. The statement in whole read: “Furthermore, the 
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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 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 at 24993

As can be seen from this passage, EPA did not rely on CAA 

section 112(c)(6); instead the Court used that provision 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 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 

EPA delists the source category.
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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 

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).

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 

determine that regulation is appropriate and necessary, after 

considering the results of the study. 76 FR 24981, 24986, and 
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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 reaffirmed 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.

Comment: One commenter believes that the D.C. Circuit will 

condemn the final rule as a result of EPA’s “misapprehension”
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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). Similarly, 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). Because the commenter believes the 

rule is bound to be rejected, 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 

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 
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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 

legitimate argument to rebut this conclusion.

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 
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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 “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 

“listing” provisions of CAA section 112(c)(9), and the standardsetting provisions of CAA section 112(d) necessarily and 

automatically apply. Therefore, EPA’s proposal to utilize the 

criteria of CAA section 112(c)(9) to inform its findings under 

CAA section 112(n)(1)(A) 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), EPA 

would be better served to consider the “residual health risk”

provisions of CAA section 112(f)(2). Those provisions provide a 
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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. 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 acknowledged 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 

112(c)(9)(B) delisting provisions as a benchmark in making that 

interpretation. The commenter asserted 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 
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the statute treated EGUs differently. The EPA views the 

disparate treatment of EGUs in a different light than commenter. 

We maintain that the only difference applies to the manner in 

which EGUs are added to the list of source categories subject to 

regulation. We do not interpret CAA section 112(n)(1)(A) as a 

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 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, 

the characteristics of exposure, the nature of the health 

effects, and the uncertainties associated with the data. 

However, EPA did not rely solely on the delisting provisions for 

evaluating hazards to public health as commenter suggests. In 

fact, EPA considered all of the factors the commenter suggests 
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in making our finding.62 Thus, our approach to evaluating hazards 

to public health and the environment based on this comment.

h. 2000 Finding (and 2005 Reversal)

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 Study63 and 

Mercury Study64, 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 

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 

 

62 76 FR 24992.

63 U.S. EPA, 1998.

64 U.S. EPA, 1997.
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Administrator discretion in her finding, and that discretionary 

decision should not be overly scrutinized, citing court 

opinion.65 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 200 finding that the Agency lacked 

sufficient evidence to conclude that non-mercury 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 

the finding, the potential harm from non-mercury 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 

 

65 “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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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. While one commenter stated that the attempted 2005 

reversal of the 2000 finding was properly rejected by the U.S. 

Court of Appeals, another commenter asserted that the 2005 

action was reasoned and proper and that EPA reverted back to the 

2000 finding 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 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 
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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 

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. 
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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, 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 

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.

66

One commenter stated that the 2000 finding ignored EO 12866.

 

66 See UARG v. EPA, 2001 WL 936363, No. 01-1074 (D.C. Cir. July 
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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, 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,67 and the NAS 

study,68 which all showed the known and potential hazards to 

public health and the environment. New technical analyses

conducted by EPA confirm that it remains appropriate and 

necessary to regulate HAP emissions from EGUs. Furthermore, EPA 

agrees with the commenters on several points raised, 

specifically that EGUs were and remain the largest anthropogenic 

source of several HAP in the U.S., that risk assessments 

supporting the 2000 finding indicated potential concern for 

several non-mercury HAP, and that several available control 

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

 

26, 2001).

67 U.S. EPA, 1997.

68 NAS, 2000.
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The EPA agrees with the commenters that Congress did not 

exempt EGUs from 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, EPA has promulgated 

regulations requiring the use of available control technology 

and other practices to reduce HAP emissions for more than 50 

industrial sectors. 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 

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 
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whether it was appropriate to regulated EGUs.

69 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.70

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,71 and EPA stands by the 

conclusions in that notice. Furthermore, 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

emissions.72 As to emission reductions, EPA cannot estimate the 

level of HAP emission reductions cannot until the Agency 

proposes a CAA section 112(d) standard after a source category 

is listed.

 

69 65 FR 79830.

70 Id.

71 65 FR 24994-24996.

72 See Chapter 13 of the Utility Study (U.S. EPA, 1998). 
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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, 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, 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-mercury metal HAP 

(including As, Cr, Ni, and Cd) were not low enough to be to 

eliminate as potential concern.73 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 

 

73 76 FR 79827.
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“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, with which we disagree, 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 pose 

known and potential hazards to public health and the 

environment. The EPA also stated in 2000 that uncertainty 

associated with the potential risk from HAP emissions justified 
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regulation of HAP emissions from EGUs. This is true because 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, 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 wholly 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 

(vacating the 2005 “delisting” action). In the preamble to the 
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proposed rule, 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 

that information. In addition, even though not required to do 
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so, 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, consent decrees, and closures. 

Some commenters are also incorrect regarding their 

assertion of certain procedural requirements associated with the 

2000 listing. The EPA did not violate CAA section 307(d) by not 

providing notice and comment opportunity before making the 

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 commenters could have also 
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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 requirement of CAA 

section 307(d). 

The EPA also disagrees with 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.

74

2. New Technical Analyses

a. General comments on new technical analyses

 

74 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, EPA has ample evidence to support a determination that 

non-mercury 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, 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, 

EPA agrees with commenters that the final rule will lead to 

substantial reductions in HAP emissions from EGUs, that control 

of the HAP will lead to public health and environmental benefits 

as discussed in the RIA, that Hg emissions from EGUs pose a 

hazard to public health, and that non-mercury HAP emissions from 
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EGUs pose a hazard to public health that warrants regulation 

under CAA section 112.

Although these new analyses were not required, 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 because it 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.75

 

75 76 FR 24988.
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The EPA disagrees with the commenter’s implication that EPA 

conducted the new analyses because of alleged flaws in the 2000 

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, EPA maintains that had it complied 

with the statutory mandate to issue CAA section 112(d) standards 

within two years of listing EGUs, 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 not required 

to reevaluate the 2000 finding. In conducting the new analyses, 

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, EPA submitted the Hg Risk TSD to the SAB, which 

“supports the overall design of and approach to the risk 

assessment and finds that it should provide an objective, 
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reasonable, and credible determination of the potential for a 

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

76 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 Willie Soon regarding the 

use of 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 nonmercury 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 2009.77

During the public comment period, 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. For the final rulemaking, 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.

b. Hg Emissions Estimates

1. Hg emissions from EGUs

 

76 U.S. EPA-SAB, 2011.

77 U.S. EPA-SAB, 2010.
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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 

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 

starting point for 2016 emissions from IPM, any 2005 
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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. 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 

should not be the same as the 2016 Hg emissions estimate given 

that compliance with CSAPR is expected to lead to some Hg 

emission reduction co-benefits. For this reason, EPA has 

included those reductions in the future-year modeling used for 

the Hg risk analysis. The EPA estimates that current Hg 

emissions are 28 tons, replacing the estimated 2010 value of 29 

tons reported at proposal. The EPA has also revised the 2016 

base estimate to 27 tons. The Any remaining inconsistency in 

EPA’s revised values is not relevant to the Hg national risk 

analysis since the 2010 emissions are not used in any of the 

risk calculations, which depend only on the modeled 2005 and 

2016 Hg emissions. 

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 
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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 

America that affects U.S. Hg deposition significantly and also 

affects it the most compared to other regions—are expected to 

continue to increase.78,79,80,81,82,83 This would affect the amount of 

 

78 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, 
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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: 

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 

 

3029–3038.

79 Jaffe D., Strode S., 2008. “Fate and Transport of Atmospheric 

Mercury from Asia,” Environmental Chemistry, 5, 121. 

80 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.

81 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.

82 Streets, D.G., Zhang, Q., Wu, Y., 2009. “Projections of Global 

Mercury Emissions in 2050.” Environmental Science & Technology

43, 2983-2988.

83 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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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 condition inflow needs 

adjustment. The first 10 days of the modeling simulation are not 

used in the analysis, which is beyond the number of days 

necessary to remove the influence of initial conditions on Hg 

deposition estimates.84 Accurate characterization of speciated 

ambient Hg inflow is problematic due to the lack of observation 

data near the boundaries of the large continental-scale modeling 

domain. The EPA has determined that the perturbations applied by 

Pongprueksa et al. (2008), of 1 ng/m3 are not realistic 

boundaries of global speciated Hg concentrations and do not 

provide directly applicable information about uncertainty

related to boundary conditions. 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 

inventory.85 A recently published comparison of global Hg 

 

84 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.

85 Selin, N.E., Jacob, D.J., Park, R.J., Yantosca, R.M., Strode, 
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emissions by continent for 2000 and 2006 was found that total Hg 

emissions from Asia (and Oceania) total 1,306 Mg/yr in 2000 and 

1,317 Mg/yr in 2006.86 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 2000.87 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, 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 disagrees with the commenter’s assertion that EPA 

has not acknowledged the dramatic decline in Hg emissions for 

the U.S. EGUs since the late 1990s. The EPA analyzed historical, 

 

S., Jaegle, L., Jaffe, D. 2007. “Chemical cycling and deposition 

of atmospheric mercury: Global constraints from observations.”

Journal of Geophysical Research-Atmospheres 112.

86 Streets et al., 2009.

87 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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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, EPA modeled Hg emissions from U.S. and non-U.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, 

EPA finds that total Hg deposition from EGUs do significantly 

impact human health.

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 

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. 
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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.88,89,90,91

c. Hg Deposition Modeling

1. General Comments on Deposition Modeling

Comment: Several commenters stated that according to the ENVIRON 

report, 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 

 

88 Caffrey et al., 2010.

89 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).

90 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.

91 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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condition treatment, the exclusion of U.S. fire emissions,92 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 (one-fifth 

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,93,94

and EPA should present results as estimates of lower and upper 

bound limits.

 

92 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.

93 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.

94 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.
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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.95,96 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 

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 

 

95 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.

96 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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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 2000.97 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 200698 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)99 suggests caution when using 

their field data to make assumptions about Hg(p) emissions from 

wildfires; the estimated particulate Hg emissions from wildfires 

is based on one field site with a limited sample size, and the 

assumptions made (such as the observed Hg(p) to carbon monoxide 

 

97 Slemr et al., 2011.

98 Streets et al., 2009.

99 Finley et al. 2009.
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ratios at this location) may not be valid on a broader scale.100

Mercury emissions from wildfires are a re-volatilization of 

previously deposited Hg.101 Given that electrical generating 

power plants are currently and historically have been a large 

Hg-emitting source, 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, EPA modeled Hg emissions from U.S. and non-U.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 analysis done 

for this rule EPA finds that total Hg deposition from EGUs do 

significantly impact human health. The ENVIRON report provides 

no risk analysis of EGU contribution. 

 

100 Id.

101 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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The EPA disagrees that research102,103 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, 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 

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.104,105 A detailed description of various plume 

 

102 Seigneur et al., 2003.

103 Seigneur et al., 2004.

104 Edgerton, E.S., Hartsell, B.E., Jansen, J.J., 2006. “Mercury 
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measurement studies is provided in EPRI Comments, Section 3.4: 

Plant Bowen, Georgia, Plant Pleasant, Wisconsin, and Plant 

Crist, Florida. One commenter believes 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 believes 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 

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 

 

speciation in coal-fired power plant plumes observed at three 

surface sites in the southeastern U.S.” Environmental Science & 

Technology 40, 4563-4570.

105 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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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.106,107 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.108 Reactions that may reduce gas phase 

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 

 

106 Kolker et al., 2010.

107 Rothenberg et al., 2010.

108 Vijayaraghavan, K., Seigneur, C., Karamchandani, P., Chen, 

S.Y., 2007. “Development and application of a multipollutant 

model for atmospheric mercury deposition.” Journal of Applied 

Meteorology and Climatology 46, 1341-1353.
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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 

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 
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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: The predicted wet deposition in the air quality 

modeling TSD was incorrectly calculated during post-processing 

of model and observation pairs. This error only influenced the 

calculation of model performance metrics. The error has been 

fixed, and the model performance metrics in the revised air 

quality modeling TSD have been updated. In response to comments, 

EPA provided additional model performance evaluation by season 

to the air quality modeling TSD. In addition, in response to 

comments, EPA has now included model performance evaluation for 

total Hg wet deposition for the 36 km modeling domain. 

The EPA disagrees that it did not conduct an assessment 

comparing CMAQ total Hg wet deposition estimates to MDN data. 
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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 characterization of wet and 

dry deposition processes relating to speciated Hg in global and 

regional scale photochemical models should be continually 

evaluated by the academic community and improved when 

appropriate. The CMAQ wet deposition of Hg has been and will 

continue to be extensively evaluated against Mercury Deposition 

Network sites.109 There is no dry deposition monitoring network, 

and the CMAQ dry deposition processes will be evaluated when 

measurement data sets become available. 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 

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 

 

109 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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estimates problematic.110 Considering the problems associated 

with TEKRAN measurements of ambient Hg and the sparse nature of 

routine measurements in the U.S., 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.111

Another commenter identified two studies as supposedly having Hg 

modeling results that are applicable to EPA’s analysis.112,113

 

110 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.

111 Lohman et al., 2006.

112 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.

113 Vijayaraghavan, K., Karamchandani, P., Seigneur, C., Balmori, 
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These studies present similar model performance metrics as 

EPA and aggregate the 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, which presents a more favorable 

evaluation. The Seigneur et al. paper114 employs a less stringent 

approach for matching observations and model estimates of total 

Hg wet deposition by calculating annual averages of both before 

comparison to make model performance seem optically better. It 

is common practice to pair modeled estimates and observations in 

space and time (weekly in this case), estimate performance 

metrics, then average all the metrics together. The latter is 

the approach taken by U.S. EPA and should have been taken by the 

studies presented by the commenter. The EPA finds the 

performance evaluation presented in the modeling TSD consistent 

with and far beyond what is presented in published articles115

deemed relevant by the commenter. In addition to the evaluation 

presented by EPA in the air quality modeling TSD, CMAQ model 

 

R., Chen, S.-Y., 2008. “Plume-in-grid modeling of atmospheric 

mercury.” Journal of Geophysical Research-Atmospheres 113.

114 Seigneur et al., 2006.

115 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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performance for total Hg wet deposition has been compared with 

other Hg models.116

The EPA agrees that the commenter accurately restated total 

wet deposition model performance information provided by EPA in 

the Air Quality Modeling TSD. To provide context, other Hg 

modeling studies show a positive bias for annual total Hg wet 

deposition.117,118 An annual Hg modeling application done by 

ENVIRON119 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.120 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)

 

116 Bullock et al., 2009.

117 Id.

118 Vijayaraghavan et al., 2007.

119 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

120 Yarwood et al., 2003.
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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 

the U.S. are the primary source of Hg to the Great Lakes and the 

Chesapeake Bay.121 The commenter also stated that the study is 

consistent with a major Hg deposition study conducted by 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.122

One commenter agreed with the Agency’s assessment of 

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 is conservative. The 

commenter stated that maximum excess local Hg deposition may be 

significantly underestimated by averaging high deposition sites 

 

121 Evers, David C. et al. 2007. “Biological Mercury Hotspots in 

the Northeastern United States and Southeastern Canada,”

Bioscience. Vol. 57 No. 1. p. 29.

122 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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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 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.123 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, 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 

 

123 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.
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power plants is not confined to a 50-km radius around the plants 

and that most emissions from power plants travel beyond 50 km.124

Several commenters stated that EPA does not adequately 

define hotspots in this proposed rule. Those same commenters 

cited a previous EPA definition of hotspots as “a waterbody that 

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).125 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.126 One of those two commenters noted that others have 

defined “hotspots as a spatially large region in which 

 

124 Seigneur et al., 2006.

125 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.

126 Evers et al., 2007.
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environmental concentrations far exceed expected values, with 

such values (i.e. concentrations) being 2 to three standard 

deviations above the relevant mean.”

127

One commenter stated that Hg concentrations are not always 

highest at sites closest to a major source. The commenter 

referred to a study by Kolker, et al. (2010)128 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 stated that wet deposition measurements were 

taken between November 2004 through December 2007 at three sites 

located downwind from the coal-fired power plant Crist in 

Pensacola, FL. The commenter stated that during this period, 

Plant Crist emitted about 230 pounds of Hg annually, about 85 

percent of which was reactive gaseous Hg.129 The commenter cited 

 

127 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.

128 Kolker, et al., 2010.

129 EPRI, 2010. Atmospheric Deposition of Mercury, Trace Metals 

and Major Ions to a Watershed Around a Coal-Fired Power Plant. 

Palo Alto, CA: 1021566.
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a study by Landing et al. (2010)130 that estimated that 22–33 

percent of wet-deposited Hg at these sites came from coal 

combustion, including regional and local sources while the 

remaining 67 to 78 percent came from the global background. The 

commenter stated that using the same data from these same wet 

deposition sites, Caffrey et al. (2010)131 found that Hg 

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. 

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. According to the 

commenter, using Hg to trace metal (As and selenium) ratios in 

 

130 Landing W.M., Caffrey J.M., Nolek S. D., Gosnell K. J., and 

Parker W. C., 2010 “Atmospheric Wet Deposition of Mercury and 

Other Trace Elements in Pensacola, Florida,” Atmospheric 

Chemistry and Physics, 10, 4867–4877.

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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precipitation collected in the same MDN in (post-scrubber) 2010, 

Krishnamurthy, et al. (2011)132 reported that Hg deposition due 

to local and regional sources had changed between -10 to +6 

percent at these sites, relative to historic measurements. The 

commenter stated that these changes were thought to represent 

upper bound estimates, since the researchers assumed that all 

Hg, As, and selenium measured in wet deposition was from local 

and regional coal combustion sources even though measured 

deposition can also include global emission sources. The 

commenter stated that, taken collectively, these findings show 

that increased local deposition, possibly due to EGUs, and 

deposition changes due to changes in EGU emissions, are small 

and within the range of natural variability.

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 

 

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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concluded that statistical analysis does not show evidence of a 

significant relationship between temporal trends in Hg emissions 

from coal-fired EGUs in Florida and Hg concentrations in 

precipitation during 1998 to 2010. According to the commenters, 

these observational studies are supported by and consistent with 

evidence that oxidized Hg emitted from coal-fired power plants 

rapidly converts to elemental Hg, significantly reducing the 

potential for “local” or nearby deposition.

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, 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 
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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 

acknowledges additional studies134 cited by those commenters that 

corroborate EPA’s conclusions. However, EPA disagrees with those 

commenters’ characterization of the methodology used to 

calculate the potential for excess local deposition. In 

response, 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, 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 

 

133 Edgerton et al., 2006.

134 Driscoll et al., 2007.
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hotspots” but rather of Hg deposition hotspots, defined as 

excess local Hg deposition around power plants, as clarified in 

the new Local Deposition TSD. 

The EPA disagrees that the analysis assumes that deposition 

of Hg is confined to a 50-km radius around power plants. The 

purpose of EPA 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, 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, 
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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, 

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 to 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. EGU-attributable 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 
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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 

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 that 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, 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 
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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 

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 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 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. 

The study135 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 

 

135 Seigneur et al., 2006.
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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.136 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 and 

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.

The information137 provided by a commenter is not relevant 

to the analysis of excess local deposition from EGUs, as it is 

based on ground level measurements of wet deposition alone. 

Changes to wet deposition over a fairly short time frame such as 

a year (the part of the study where the coal-fired power plant 

(Crist) emitting Hg installed controls) are not expected to 

provide meaningful information about the effectiveness of 

 

136 Id.

137 EPRI, 2010.
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control technology. Wet deposition is highly variable from year 

to year and is subject to varying meteorological wind patterns 

from year to year. A more appropriate observation based 

assessment would be to evaluate both wet and dry deposition.

d. Hg Risk TSD

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 (MMaps) 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 account for the dynamics of ecosystems 

that affect Hg bioaccumulation in fish, cannot consider non-air 
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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 

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 

 

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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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. 

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 

MMaps 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 

 

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.
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subsequent changes in atmospheric deposition need to be weighed 

against the amount of Hg already in an ecosystem,143 (4) the 

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 

 

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.

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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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 

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, EPA 

did not adequately screened 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 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 
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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 

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 
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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 

estimates of uncertainty available in the existing 

literature.146

The SAB peer review committee specifically addressed the 

Mercury Cycling Model 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 

 

146 U.S. EPA-SAB, 2011.
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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 

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 

 

147 U.S. EPA-SAB, 2011.

148 Orihel et al., 2007. 

149 Orihel et al., 2008.

150 Harris et al., 2007. 
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level changes is sufficiently robust for its application in this 

risk assessment.”

151

Based on the responses of the SAB peer review committee, 

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 

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, 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 

 

151 U.S. EPA-SAB, 2011. 

152 U.S. EPA-SAB, 2011. 
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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. 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, 

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, EPA clarifies that the Hg Risk TSD did not 

directly use the Mercury Maps model. Instead, 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 steady-state 
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conditions in apportioning fish tissue Hg levels and risk, 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 patterns of 

Hg deposition and strengthens the approach used in the Revised 

Hg Risk TSD. 

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 

 

153 Orihel et al., 2007.

154 Orihel et al., 2008.

155 Harris et al., 2007.
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indicate subsistence fishing. One commenter stated that by 

including watersheds with as few as 25 members of individuals 

living in poverty, 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”

and stated that if other studies exist, 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 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 
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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 

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 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 atrisk, 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, EPA clarifies that 
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“subsistence fishers” are defined as individuals who rely on 

noncommercial fish as a major source of protein (U.S. EPA, 

2000).156 This definition is reflected in the range of fish 

consumption rates used in estimating risk. The likely presence 

of this type of 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 that 

were 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. 

 

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, DC. EPA 823-B-00-007.

157 U.S. EPA-SAB, 2011.
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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 

Revised Hg Risk TSD, 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. 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, 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, EPA uses the U.S. Census data 

assess whether a 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.
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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, EPA links poverty with 

subsistence fishing, as EPA only modeled locations with poor 

source populations. However, in modeling these three 

populations, 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,158 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, thus can be included 

 

158 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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in the risk assessment. Consequently, while there is the 

potential for including some watersheds in the analysis that may 

not have currently active subsistence fishing activity, there is 

also the very real possibility 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.

The 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. However, subsistence fishers active at inland 

freshwater watersheds are likely to experience the highest 

levels of individual risk as a result of exposure to U.S. EGUattributable Hg. Therefore, EPA focuses on this group of 

subsistence fishers in the risk assessment and did not evaluate 

exposure for the general population related to Hg exposure 

through seafood.

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 

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 
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a similar factor. Several commenters stated that the source of 

EPA’s selected loss factor159 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.160,161,162,163,164 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 

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 

 

159 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.

160 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.

161 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. 

162 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.

163 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. 

164 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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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 

(1997) study 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). 

The Morgan (1997) study provides a range of adjustment factor 

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, 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. The Morgan (1997) study explains that 

preparation/cooking of fish results in an increase in MeHg 

levels per unit fish 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, EPA disagrees that these studies considered 
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collectively contradict the cooking loss factor in the analysis. 

Specifically, the first study165 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,166 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.167 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 study168

found a modest but statistically insignificant increase in Hg 

levels for most of the cooking methods assessed, which is 

directionally consistent with EPA’s cooking loss adjustment. The 

fifth study169 only addressed the issue qualitatively, thus 

cannot be used for the cooking loss factor. When considered 

 

165 Farias et al., 2002. 

166 Perelló et al., 2008. 

167 Torres-Escribano et al., 2011

168 Armbruster et al., 1988.

169 Gutenmann et al., 1991.
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collectively, 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 

study170 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).171 Therefore, EPA interprets the 

fish consumption rates provided in the Burger et al. study as 

representing as cooked/prepared and not for raw fish and for 

that reason, application of a preparation/ cooking adjustment 

factor is required. The Shilling et al., (2010) study172 used 

different sized models of cooked fish filets and therefore these 

consumption rates are also interpreted as represented as 

 

170 Morgan et al., 1997. 

171 Burger et al., 2002.

172 Shilling, Fraser, Aubrey White, Lucas Lippert, Mark Lubell 

(2010). Contaminated fish consumption in California’s Central 

Valley Delta. Environmental Research 110, p. 334-344.
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cooked/prepared and not raw fish. One study173,174 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.

175,176 The 

commenter stated that these default consumption rates are 

derived from various studies and generally are based on 90th or 

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 

 

173 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.

174 Personal communication, Dr. Dellinger, September 27, 2011

175 U.S. EPA. 1991. Risk Assessment Guidance for Superfund 

(RAGS). Part C 1991 EPA/9285.7-01C. October.

176 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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exposure (“RME”) scenario,177 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 

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 

 

177 U.S. EPA. 1989. Risk Assessment Guidance for Superfund 

(RAGS). EPA/540/1-89/002. December.
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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 the commenter, an analysis of EPA’s 

database by the SAB indicated that 60 percent of the watersheds 

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 
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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 

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.
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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, EPA is interested in those individuals who are most 

at-risk, which includes those who consume the most fish. For 

that reason, EPA considered a range of high-end fish consumption 

rates including the 99th percentile representing the most highlyexposed individuals. In responding to the SAB peer review, 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 focus on the most highly-exposed individuals is 

consistent with the appropriate and necessary finding and the 

treatment of other HAP under CAA section 112. 

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 

substantial increase in ingestion rates relative to the mean or 
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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, EPA asserts that it 

is reasonable to include these consumption rates as 
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representative of the most at-risk populations. In these cases, 

however, 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 surveys178 and specialized 

studies.179,180,181,182,183 Several studies identified additional 

fishing populations with subsistence or near subsistence 

consumption rates, including urban fishing populations 

 

178 Burger et al., 2002.

179 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.

180 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.

181 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.

182 Tai, S. 1999. “Environmental Hazards and the Richmond Laotian 

American Community: A Case Study in Environmental Justice.”

Asian Law Journal 6: 189.

183 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),184,185,186 Laotian 

communities,187 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.188 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.189

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, 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, EPA 

moved the summary table to the main body in the Revised Hg Risk 

TSD. In identifying these studies, EPA focused on surveys for 

subsistence fishers that were applicable at the broader regional 

 

184 Burger et al., 1999a.

185 Burger et al., 1999b.

186 CalEPA, 1997.

187 Tai, 1999..

188 Corburn, 2002.

189 U.S. EPA-SAB, 2011.
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or national level. In the Hg Risk TSD, EPA acknowledged the 

smaller sample sizes for some of the subsistence fisher groups, 

and in several cases EPA did not use the 99th percentile 

consumption rates because the sample sizes were too low to 

support this level of resolution.

The EPA disagrees with the comment that it did not provide 

a rationale for choosing the highest 75th percentile fish tissue 

concentration across lakes and rivers in a watershed. However, 

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, 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. 

The EPA generally agrees with the comment that some 

fraction of subsistence fishers likely consume fish without 

consideration for size (given dietary necessity), however, EPA 

considers it reasonable to assume that a subset of subsistence 

fishers could target larger fish on order to maximize the 

potential consumption per unit of fishing effort. The EPA uses 
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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.”

190 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. Regarding the 7-inch 

criteria, for the Revised Hg Risk TSD, EPA clarified that this 

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 

 

190 U.S. EPA-SAB, 2011.
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such as bass, walleye and northern pike have higher minimum size 

limits).191

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 RfD192 is based on 

sound science, which was supported by the findings of the NAS 

Study,193 and that EPA appropriately applied the RfD in the Hg 

risk assessment. The commenters also stated that recent studies 

 

191 Pennsylvania Fish and Boat Commission. 2011. Summary Book: 

2011 Pennsylvania Fishing Laws & Regulations available at: 

http://fishandboat.com/fishpub/summary/inland.html.

192 U.S. Environmental Protection Agency – Integrated Risk 

Information System (U.S. EPA-IRIS). 2001. Methylmercury (MeHg) 

(CASRN 22967-92-6). Available at 

http://www.epa.gov/iris/subst/0073.htm

193 NAS, 2000.
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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, EPA 

relied on the flawed Faroe Islands’ children study and ignored 

the Seychelles Islands study,194 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) 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 

 

194 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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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,195 and Poland.196

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 

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 

 

195 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).

196 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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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)197 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 

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 

 

197 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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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 study198 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 

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. 

 

198 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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Several commenters question the relationship between 

cardiovascular effects and MeHg exposure. Two commenters cited 

studies examining the relationship between MeHg exposure and 

cardiovascular effects,199,200,201,202,203,204 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 

fish advisories are often unsuccessful in changing behavior.205,206

One commenter noted the important protective role of dietary 

 

199 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.

200 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.

201 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.

202 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.

203 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.

204 Mozaffarian, Dariush. 2011. “Mercury Exposure and Risk of 

Cardiovascular Disease in Two U.S. Cohorts,” N Engl J Med 364: 

1116-1125.

205 Hibbeln et al. 2007.

206 Mozaffarian, et al., 2011
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selenium against MeHg toxicity because the binding affinity of 

Hg to Se is much higher than binding to sulfur.

Response: EPA agrees with the commenter that 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, U.S. 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 NAS207 and an independent scientific review 

panel convened as part of the IRIS process208 advised strongly 

against using results from a study that at the time had not 

shown an association between MeHg exposure and adverse effects. 

Further, EPA disagrees with the commenter that EPA based the 

MeHg RfD solely on results from the Faroe Islands population and 

disagrees that the information underlying the RfD is “poorly 

 

207 NAS, 2000.

208 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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explained”. The EPA has provided detailed documentation for the 

choices underlying calculation of the RfD.209,210,211 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, 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 

contributing to risk of adverse effects, and that reductions in 

 

209 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

210 U.S. Environmental Protection Agency – Integrated Risk 

Information System (U.S. EPA-IRIS). 2001. Methylmercury (MeHg) 

(CASRN 22967-92-6). Available at 

http://www.epa.gov/iris/subst/0073.htm

211 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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exposures above the RfD can lead to incremental reductions in 

risk.” However, 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 U.S. EPA 

on the appropriate bases for a MeHg RfD, NAS specifically 

recommended that EPA use neither the study nor the uncertainty 

factor employed by Agency for Toxic Substances Disease Registry 

(ATSDR) in the calculation of the minimal risk level.212

The EPA disagrees that the uncertainty factor is “unusually 

high”. The uncertainty factor used in calculation of the 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 NAS213 and an independent panel of scientific peer 

reviewers convened as part of the IRIS process214. 

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 

a threshold] is indicated by the fact that, of the K power 

 

212 NAS, 2000.

213 Id.

214 U.S. EPA, 2001b.
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models, K = 1 provided a better fit for the endpoint models than 

did higher values of K.”

215

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. 

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.216 One study notes that in the NHANES data 

(1999 to 2004), the highest five percent of women’s blood Hg 

exceeded 8.2 microgram per liter (μg/L) in the Northeast U.S. 

and 7.2 μg/L in coastal areas.217 Higher levels have been 

reported among subjects known to consume fish. For example, one 

 

215 U.S. EPA-IRIS, 2001.

216 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.

217 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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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.218 Note that some 

publications have reported Hg effects in U.S. populations near 

the current U.S. RfD.219,220 Also, 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.221,222

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 

 

218 Hightower Jane M, Moore Dan. Mercury levels in high-end 

consumers of fish. Environ Health Perspect. 2003 Apr;111(4):604–

608. 

219 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.

220 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.

221 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.

222 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.
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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.”

223 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 

of fish, for example) show exposures above the this level. One 

study estimated very high blood Hg levels at the 99th percentile 

 

223 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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for females of child-bearing age.224 Other published studies have 

shown that various population groups can have high blood Hg 

levels.225,226,227,228,229 For example, one study found that 83 percent 

of the NHANES Asian population exceeded the RfD-equivalent blood 

mercury level.230

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.231 The EPA also documented the 

independence of PCB and MeHg effects in the Faroe Islands 

 

224 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.

225 Id.

226 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.

227 Hightower and Moore, 2003.

228 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.

229 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.

230 Hightower et al., 2006.

231 NAS, 2000.
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population.232 The NIEHS concluded that both PCB and Hg had 

adverse effects. 233 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.234 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.235 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.236

This is an exposure study rather than a study on measures of 

neurobehavioral or any other health endpoint. TCEQ noted that 

none of the Caddo Lake study participants had blood Hg levels 

 

232 U.S. EPA, 2001a.

233 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.

234 NAS, 2000.

235 Budtz-Jørgensen, E., N. Keiding, and P. Grandjean. 1999. 

Benchmark modeling of the Faroese methylmercury data. Final 

Report to U.S. EPA.

236 DSHA, 2005.
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above the 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.237,238,239,240 The 

Agency’s concern with the likelihood of human exposure to 

multiple contaminants is reflected in the multi-chemical scope 

 

237 U.S. EPA. 1986. Guidelines for the Health Risk Assessment of 

Chemical Mixtures. U.S. Environmental Protection Agency, Office 

of Research and Development, Washington, DC. September. 

EPA/630/R-98/002. Available at 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=2256

238 U.S. EPA. 1999. Guidance for Performing Aggregate Exposure 

and Risk Assessments. U.S. Environmental Protection Agency, 

Office of Pesticide Programs, Washington, DC. October. Available 

at http://www.pestlaw.com/x/guide/1999/EPA-19991029A.html

239 U.S. EPA. 2000a. Supplementary Guidance for Conducting Health 

Risk Assessment of Chemical Mixtures. U.S. Environmental 

Protection Agency, Risk Assessment Forum, Washington, DC. 

EPA/630/R-00/002. Available at 

http://www.epa.gov/ncea/raf/pdfs/chem_mix/chem_mix_08_2001.pdf

240 U.S. EPA. 2003a. Framework for Cumulative Risk Assessment. 

Risk Assessment Forum, U.S. Environmental Protection Agency. 

Washington, DC. EPA/630/P-02/001F. EPA/600/P-02/001F. Available 

at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=54944
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of the rulemaking. However, 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.”

241

The EPA agrees that additional qualitative discussion about 

uncertainty would improve the Revised Hg Risk TSD. The SAB also 

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, and EPA is preparing a revised 

TSD that will address the SAB’s recommendations, including a 

more complete discussion of uncertainties including the RfD.

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. 

 

241 U.S. EPA-SAB, 2011.
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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.”

242 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).243 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.”

244 As noted in other studies,245,246 a decrease of 1-2 

points at the mean results in a much larger decrease in those 

with IQs that are much lower or higher than the mean. 

 

242 U.S. EPA-SAB, 2011.

243 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

244 U.S. EPA-SAB, 2011.

245 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.

246 Bellinger DC. 2005. Neurobehavioral Assessments Conducted in 

the New Zealand, Faroe Islands, and Seychelles Islands Studies 

of Methylmercury Neurotoxicity in Children. Report to the U.S.

Environmental Protection Agency. EPA-HQ-OAR-2002-0056-6045.
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Although EPA disagrees that the IQ results are too 

uncertain to rely upon, 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.”

247 The EPA is following up the 

SAB’s recommendation by deemphasizing the IQ analysis and 

placing that analysis in an appendix to the revised TSD. 

The SAB, however, supported the use of the IQ dose-response 

function calculated by EPA in the Hg Risk TSD. The SAB noted, 

“The function used came from a paper by Axelrad and Bellinger 

(2007) that seeks to define a relationship between methylmercury 

 

247 U.S. EPA-SAB, 2011.
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exposure and IQ. A whitepaper by Bellinger (Bellinger, 2005)248

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.”

249

The EPA disagrees that EPA has overstated or failed to 

review the scientific literature on cardiovascular effects from 

MeHg exposure. As summarized in the preamble to the proposal, 

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.”

250 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 exposures, as there is no consensus 

among scientists on the dose-response functions for these 

 

248 Bellinger, 2005.

249 U.S. EPA-SAB, 2011.

250 76 FR 25001
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effects, and there is inconsistency among available studies as 

to the association between MeHg exposure and various 

cardiovascular system effects. In the future, 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.251,252 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.253 That study 

suggests that at normal Japanese dietary intake of MeHg and fish 

 

251 Oken et al., 2008,

252 Lederman et al., 2008.

253 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 

seafood intake: neonatal behavioral assessment scale results of 

Tohoku study of child development.” Environ Res 110, 699-704.
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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.254,255,256,257258,259,260 Recent studies261,262,263 and analyses 

indicate the potential for nutrients in fish (particularly 

marine fish) to mask some of the observed adverse effects of 

 

254 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. 

255 Budtz-Jorgensen, E.; Grandjean, P.; Weihe, P. 2007. 

“Separation of risks and benefits of 16 seafood intake.”

Environmental Health Perspectives. Vol. 115, 323-327.

256 Choi et al., 2008a. 

257 Choi et al., 2008b.

258 Oken et al., 2008.

“

259 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.

260 Suzuki, et al., 2007.

261 Oken et al., 2008.

262 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.

263 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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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.”

264 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.”

265

6. General comments on Hg Risk Assessment

Comment: Several commenters generally supported the Hg risk 

assessment, but several other commenters generally disagreed 

 

264 U.S. EPA-SAB, 2011.

265 Id.
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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, MMAPs, 

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 

effect despite evidence to the contrary, and created 
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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 reduction of 41 tons of Hg in 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 

demonstrable evidence that anyone in the U.S. has suffered 
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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 

TSD, they could not assess key questions, such as the nationwide representativeness of the fish tissue data. 
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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. 

One commenter questions why EPA has departed from the CAA 

section 112(n) risk comparison to the 1 in 1 million to use the 

RfD for Hg.

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 
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additional factors include: (a) spatial gradients in the 

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.”

266

 

266 U.S. EPA-SAB, 2011.
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Furthermore, the SAB concluded, “The 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 oil-fired EGUs, provided that our recommendations are fully 

considered in the revision of the assessment.”

267 Although the 

SAB did indicate difficulty in evaluating the risk assessment 

based solely on the Mercury Risk TSD, the panel was able to 

obtain enough additional information through the peer review 

process to make the determination that “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.”

268 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.”

269 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 TSD 

available in the rule docket. 

 

267 Id.

268 Id.

269 Id.
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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 

peer review, EPA strongly disagrees with commenter statements 

that the results reported in the Hg 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, thus, does 

not repeat those responses here. Based on the review by the SAB, 

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 are reasonable and appropriate. The EPA 
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asserts that the Tetra Tech analysis does not fully cover 

subsistence fishers likely to experience elevated U.S. EGUrelated Hg exposure. Specifically, the risk estimated cited in 

the comment reflects application of a number of behavioral 

assumption 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. The Tetra Tech 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. The Tetra Tech 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 
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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. 

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 

risk analysis shows that U.S. EGU-attributable Hg deposition 

results in up to 29 percent of modeled watersheds having the 

potential for subsistence level freshwater fish consumers with 

total Hg exposures exceeding the RfD to have at least 5 percent 

of total Hg risk contributed by U.S. EGUs, and up to 10 percent 

of modeled watersheds having the potential for subsistence level 

freshwater fish consumers to have Hg exposures exceeding the RfD 

due to Hg emissions from U.S. EGUs even before considering Hg 

exposures due to other sources. Hg 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 
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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 

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.”

270 In response to the SAB’s 

recommendations, 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, EPA assessed the 

Hg-related health risk for 40 watersheds. Because EPA did not 

find any fish tissue data for new 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 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. EGU-

 

270 U.S. EPA-SAB, 2011.
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attributable Hg deposition are not matched by watershed. In 

other words, 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. EGU-attributable 

Hg. Therefore, the total and U.S. EGU-attributable 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, 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 studies (Orihel et al., 2007, Orihel et al., 2008 

and Harris et al., 2007) 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, EPA agrees that the subset of watersheds in the 

risk analysis have somewhat higher U.S. EGU deposition than the 
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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. 

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. Based on the Hg 

risk assessment, average EGU-attributable fish tissue Hg 

concentrations will be decreased by 65 percent. Likewise, the 

number of modeled watersheds with populations potentially atrisk from Hg emissions from U.S. EGUs will decline from 62 

percent in 2005 to 28 percent in 2016. Emissions reductions due 

to regulation of Hg under CAA section 112 should result in 

additional reductions in U.S. EGU-attributable fish tissue Hg 

concentrations and modeled watersheds with populations 

potentially at-risk.

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 
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recommendation. The EPA disagrees that the IQ effects at the 50th

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. 

Regarding the commenter who questioned the alleged change 

in risk metrics to use the RfD approach, the commenter is 

referring to cancer risk (i.e., a 1 in 1 million probability of 

developing cancer over a lifetime due to a specific chemical 

exposure). For Hg, EPA focused on the potential for 

neurodevelopmental effects in the children born to mothers 

exposed to MeHg during pregnancy through fish consumption. This 

health endpoint is a non-cancer endpoint, and risk in this 

context is assessed by comparing an estimate of daily exposure 

to MeHg for the mother to the MeHg RfD. Values greater than one 

(i.e., exposures that exceed the RfD) are considered to 

represent an exposure that could represent a public health 

hazard, this reflecting the methodology and underlying 

epidemiological data used in deriving the MeHg RfD.

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 
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the SAB said the Mercury 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, 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 adequate 

opportunity to comment on the Hg risk assessment.

e. Non-mercury HAP Case Studies

1. Emissions for non-mercury case studies 

Comment: The commenters raised concerns about a wide variety of 

aspects of EPA’s approach for emissions used for the non-mercury

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 
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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, 

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 agrees with commenters’

recommendations to use statistical outlier tests, but has 

applied tests different from those suggested by the commenters. 

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 
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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. The EPA conducted regression analyses between metals 

emissions measured at the site and predicted from the equations 

and demonstrates the poor predictive capability of these 

equations, concluding that emission test data is a more accurate 

predictor of actual emissions, and emission factors based on the 

arithmetic mean when test data are not available. 

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. The EPA disagrees with the commenter’s 

assertion that any impact of scrubbers will impact the case 

study analyses. In EPA’s final case study analysis, 6 facilities 

have risk greater than 1 in 1 million, and of these, four 

facilities have Cr as the risk driver (James River, Conesville, 

TVA Gallatin, and Dominion – Chesapeake Bay). For these 
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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-mercury case 

studies. In any case, EPA disagrees with the commenters’

conclusions about the impacts of scrubbers on Cr speciation and 

provides evidence that impacts of scrubbers on Cr speciation can 

have the opposite 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 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, EPA agrees with commenters’ 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-mercury Risk Case Study 

Comment: One commenter stated that EPA’s case study assessment 

reaffirms the need to regulate HAP emitted by both coal and oil-
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fired 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-mercury HAP indicated a cancer risk 

greater than or equal to the one in one million threshold level 

required to delist a source category under CAA section 112.

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 regulated those four and not 

the other 537. Another commenter stated that EPA found only a 

“few” facilities that have estimated maximum cancer risks in 
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excess of one in a million, and that this does not justify 

regulating all non-mercury 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-mercury HAP emissions from EGUs are associated with serious 

human health effects. According to the commenter, 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-mercury 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, EPA concluded that the risks from oil-fired units would 

result in only one new cancer case every five 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 one million, with the highest at eight 

in one million.
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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 

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, EPA apparently decided that they 

were justified to regulate all non-mercury HAP for all sources 

in this category. 

Several commenters stated that EPA’s assumption that 

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.
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One commenter asserts that because the alleged health 

benefits are derived from total exposure, 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, EPA simply notes that its 

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, 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-mercury

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 AERMET and AERMET. The EPA

remodeled the case study facilities using the current versions 

of AERMINUTE (version 11059), AERMET (version 11059), and AERMOD 
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(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 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-mercury metal HAP, acid gas 

HAP, and organic HAP, with a smaller set of random recipients. 
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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 

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. Furthermore, 

EPA did not base the appropriate finding on just the case study 

analysis as explained in the preamble to the proposed rule.

The EPA disagrees with the commenter’s assertion that the 

health effects associated with exposures to non-mercury HAP from 

U.S. EGUs are mischaracterized in the preamble to the proposed 

rule. The discussion of the health effects of non-mercury 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-mercury HAP (some of which have been determined to be 

carcinogenic to humans) based on peer reviewed scientific 
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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, EPA’s recent risk 

assessments of 16 EGU case studies, performed with more recent 

data and refined scientific methods, indicate that there are 

still multiple 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-mercury HAP 

risk analysis in the context of background cancer risk. As 

explained in the preamble to the proposed rule, 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 
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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 

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, EPA does not agree with the 

commenter and maintain 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 1989271 and codified by CAA 

 

271 54 FR 38044
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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 

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, EPA has up to 8 years after 

the promulgation of the technology-based emission limits for 
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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, 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 

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 
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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 

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, 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.272

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 

 

272 U.S. EPA, 2011c.
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existing URE values (i.e., values derived by the Integrated Risk 

Information System,273 California Department of Health 

Services,274 and the Texas Commission on Environmental 

Quality275), 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?

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.

 

273 U.S. EPA, 1998. Integrated Risk Information Service (IRIS) 

assessment for hexavalent chromium. Available at: 

http://www.epa.gov/ncea/iris/subst/0144.htm.

274 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.

275 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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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 

including the IARC,276 the World Health Organization,277 and the 

European Union’s Scientific Committee on Health and 

Environmental Risks.278 In their 12th Report of the Carcinogens, 

 

276 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.

277International Labour Organization/United Nations Environment 

Programme, World Health Organization (WHO), 1991. Nickel. In 

Environmental Health Criteria No 108 Geneva.

278European 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 
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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 

sites critical for carcinogenesis, thus allowing consideration 

and evaluation of these compounds as a single group”.

279 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 

 

http://ec.europa.eu/health/ph_risk/committees/04_scher/docs/sche

r_o_034.pdf

279 NTP, 2011.
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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).280,281,282 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 review283 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. 

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, EPA 

considers all Ni compounds to be carcinogenic as a group and 

does not consider Ni speciation or Ni solubility to be strong 

 

280 Oller A. Respiratory carcinogenicity assessment of soluble 

nickel compounds. Environ Health Perspect. 2002, 110:841-844.

281 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.

282 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.

283 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.
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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.284,285

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 

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, EPA also considers it reasonable to use a value that 

is 50 percent of the IRIS URE for Ni subsulfide for providing an 

 

284 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.

285 NTP, 1996.
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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 

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.
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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,”

286 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 

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.

Two EPA also disagrees that units were assumed to operate 

100 percent of the time. The dispersion modeling performed for 

 

286 U.S. EPA, 2011c.
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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 1989287 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 

 

287 54 FR 3804
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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.

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 

other primary emissions (such as SO2) that can lead to potential 

acidification of ecosystems.

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

is not adopting an emissions standard based on its authority 

under CAA section 112(d)(4) in the final rule. The EPA first 

notes that the Agency’s authority under CAA section 112(d)(4) is 

discretionary. That provision states that EPA “may” consider 
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established health thresholds when setting emissions standards 

under CAA section 112(d). By the use of the term “may,” Congress 

clearly intended to allow EPA to decide not to consider a health 

threshold even for pollutants that have an established 

threshold. As explained in the preamble to the proposed rule, it 

is appropriate for EPA to consider relevant factors when 

deciding whether to exercise its discretion under CAA section 

112(d)(4), and the language of that provision does not prevent 

the Agency from considering factors not specifically enumerated. 

To interpret the statute as commenters suggest would effectively 

require the Agency to establish CAA section 112(d)(4) standards 

whenever there is an established health threshold for a HAP. The 

EPA has considered the public comments received and is not 

adopting an emissions standard under CAA section 112(d)(4) for 

the reasons explained below and in the preamble to the proposed 

rule.

First, as explained in the preamble to the proposed rule, 

EPA maintains that the potential cumulative public health and 

environmental effects of acid gas 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). The EPA did not receive information regarding 

facility-specific emissions of all the acid gases from EGUs as 
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well as sources that may be co-located with EGUs or nearby such 

sources. Additional data were also 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 any of the EGU subcategories under CAA 

section 112(d) that take into account the health threshold for 

acid gases, particularly given that the Act requires EPA’s 

consideration of health thresholds under CAA section 112(d)(4) 

to protect public health with an ample margin of safety. The 

commenters’ assertions that EPA has sufficient data, even for 

HCl, are incorrect, and it appears that they believe that EPA 

can establish a CAA section 112(d) standard for HCl and ignore 

the other acid gas HAP, a belief that is also incorrect. Second, 

the concerns expressed by EPA in the preamble to the proposed 

rule regarding the potential environmental impacts and the 

cumulative impacts of acid gases on public health were not 

assuaged by the comments received.

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

considered the co-benefits of setting a conventional MACT 

standard for HCl. The EPA considered the comments received on 

this issue and maintains that the co-benefits are significant 

and provide an additional basis for the Administrator to 

conclude that it is not appropriate to exercise her discretion 
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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.288 The EPA consequently does 

not accept the argument that it cannot consider reductions of 

criteria pollutants, for example in determining whether to take 

or not take certain discretionary actions, such as whether to 

adopt a risk-based standard under CAA section 112(d)(4). There 

appears to be no valid reason that, where EPA has discretion in 

what type of standard to adopt, 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 

 

288 See S. Rep. No. 101–228, 101st Cong. 1st sess. at 172.
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— neither of which EPA is doing — but rather whether to make the 

discretionary choice to regulate certain HAP based on the MACT 

approach and whether EPA must put blinders on and ignore 

collateral environmental benefits when choosing whether or not 

to exercise that discretion. The EPA knows of no principle in 

law or common sense that precludes it from doing so.

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-mercury 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-mercury HAP 

EPA produced one study on chronic inhalation risk assessment 

that identified three sites with cancer risks greater that one 

in one million for Cr(VI), which was authored by EPA staff and 

not peer reviewed. One commenter stated that EPA study is based 
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on misinformation and overestimates assumptions, and that EPA 

has no data demonstrating health impacts from EGU emissions of 

non-mercury HAP, or the benefit from reducing such emissions. 

Two commenters stated that no benefits will be derived from the 

non-mercury HAP emission reductions associated with the proposed 

rule because no non-mercury HAP health risks were proven, and 

that no showing was made that EGU non-mercury 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-mercury metals 

in order to determine appropriateness of proposing emissions 

standards for non-mercury 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 
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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. 

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.289

In contrast to the approach used in the EPRI analysis, 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 

long-term (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]

 

289 Appendix W to 40 CFR 51
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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 

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 2009.290 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, 

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 

 

290 U.S. EPA-SAB, 2010. 
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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 research291 that is irrelevant to the question 

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.,292 acid gases can 

significantly contribute to acidification. The EPA published a 

comprehensive risk assessment of acidification effects of 

nitrogen and sulfur deposition293 and a policy assessment.294

 

291 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 & 

Technology 45 (5), 1887-1894.

292 Id.

293 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 
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Given the extent and importance of the sensitive ecosystems 

evaluated in the review of nitrogen and sulfur deposition any 

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 experimental results 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 risk 

assessment for NOX and SOX (U.S. EPA, 2009). Furthermore, the 

commenter is factually incorrect that EPA is justifying that it 

is appropriate and necessary to regulate HAP emissions from EGUs 

 

<http://www.epa.gov/ttn/naaqs/standards/no2so2sec/data/NOxSOxREA

Sep2009MainContent.pdf>.

294 U.S. Environmental Protection Agency (U.S. EPA). 2011. 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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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, EPA agrees that there are 

potential environmental risks from exposures of ecosystems 

through Hg and non-mercury HAP deposition. The EPA cited 

relevant articles from the special edition of Ecotoxicology295

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-mercury HAP from 

EGUs

In response to peer reviews of both the Hg and non-mercury

HAP risk analyses, and taking into account public comments, we 

conducted revised analyses of the risks associated with U.S. EGU 

emissions of Hg and non-mercury HAP. These revised analyses 

demonstrated that the risk results reported in the preamble to 

the proposed rule are robust to the revisions made to the risk 

analyses. 

 

295 Ecotoxicology 17:83-91, 2008
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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.296 In the revised Hg 

Risk TSD, up to 24 percent of modeled watersheds have potential 

total Hg exposure greater than the RfD and U.S. EGU-attributable 

Hg deposition accounts for 5 percent or more of total deposition 

to those watersheds. In the revised Hg Risk TSD, U.S. EGUs 

contribute to potential exposure greater than the RfD in 10 

percent of modeled watersheds, even excluding consideration of 

other U.S. and non-U.S. sources of Hg deposition. Given that 1) 

the percent of modeled watersheds with populations potentially 

at-risk increased from 28 to 29 percent in the revised risk 

assessment, 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 are a hazard to public health is confirmed by the 

revised Hg Risk TSD.

With regards to the revised non-mercury 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 

 

296 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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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. There were also two facilities with coal-fired 

EGUs with maximum individual cancer risks at one in a million, 

for a total of six facilities that meet or exceed the criterion 

for EGUs to be regulated under CAA section 112. In the preamble 

to the proposed rule, we reported that the maximum individual 

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 nonmercury HAP from U.S. EGUs are a hazard to public health is 
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confirmed by the revised non-mercury risk inhalation case 

studies.

While we did not do new analyses on these topics, we also 

reiterate that 1) Hg emissions from U.S. EGUs are 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 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 3) 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. These findings independently support a determination 

that it is appropriate to regulate Hg and non-mercury HAP 

emissions from EGUs. In addition, we have identified effective 

controls available to reduce Hg and Non-mercury HAP emissions.

Our revised analyses still show that in 2016 the hazards 

posed to human health and the environment by HAP emissions from 

EGUs will not be addressed by other sections of the CAA; 

therefore, it is necessary to regulate EGUs under section 112. In 
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addition, based on evaluation of the regulations required by the 

CAA, including the recent CSAPR, it is necessary to regulate EGUs 

under section 112 because the only way to ensure permanent 

reductions in U.S. EGU emissions of HAP and the associated risks 

to public health and the environment is through standards set 

under 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 Hg Risk 

TSD shows that a substantial percent of modeled watersheds with 

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 of 29 tons in 

our risk analysis compared to the most recent estimate of 27 

tons, we do not expect that this small change would affect our 

finding that Hg emissions from U.S. EGUs are a hazard to public 

health. 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 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 section 112.

We reiterate that it is necessary to regulate HAP emissions 
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from EGUs because 1) even though the hazards from Hg will not be 

resolved through regulation under section 112, incremental 

reductions in Hg are important because as exposure above the RfD 

increases the likelihood and severity of adverse effects 

increases, 2) we cannot be certain that the identified cancer 

risks attributable to 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 section 112 is the 

only way to ensure that 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 EGUs under section 112. Therefore, 

the agency affirms its finding that it remains appropriate and 

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

112, and the inclusion of coal- and oil-fired EGUs on the CAA 

section 112(c) list of source categories regulated under CAA 

section 112.

IV. Denial of Delisting Petition
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During the comment period, the Utility Air Regulatory Group 

(UARG) submitted a petition pursuant to CAA section 112(c)(9), 

asking the Agency to delete the EGU source category from the 

list of source categories to be regulated under CAA section 112. 

A copy of that petition has been placed in the docket for 

today’s rulemaking. In support of its petition, UARG presents an 

analysis of the cancer and noncancer risks associated with all 

coal-fired EGUs in the U.S. The UARG asserts that its analysis: 

1) demonstrates that emissions of HAP from EGUs do not cause any 

cancer risks greater than 1 in a million; 2) demonstrates that 

emissions of HAP from EGUs do not exceed a level which is 

adequate to protect public health with an ample margin of safety 

with respect to health effects other than cancer and which will 

result in no adverse environmental effect, and; 3) is consistent 

with documents it characterizes as EPA guidance. We disagree 

with UARG’s assertions and for the reasons set forth below, are 

denying UARG’s petition to delist EGUs from the CAA section 

112(c) source category list.

A. Requirements of CAA Section 112(c)(9)

Section 112(c)(9)(B) of the CAA provides that “[t]he 

Administrator may delete any source category” from the CAA 

section 112(c) source category list if the Agency determines 

that: (i) for HAP that may cause cancer in humans, no source in 
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the category emits such HAP in quantities that “may cause a 

lifetime risk of cancer greater than one in one million” to the 

most exposed individual; and (ii) for HAP that may result in 

human health effects other than cancer or adverse environmental 

effects, “emissions from no source in the category or 

subcategory concerned...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 

both clause (i) and clause (ii) have been met. The HAP emissions 

from EGUs present both cancer risks and non-cancer human health 

effects or adverse environmental effects and, thus, the

requirements of both CAA section 112(c)(9)(B)(i) and (ii) must 

be met. We evaluated the cancer and non-cancer risks association 

with HAP emissions from EGUs.

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.

As explained in section V of this final rule, the Agency 

analyzed non-Hg inhalation risks from 16 EGU facility case 

studies. That analysis demonstrates that there are 6 EGU 
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facilities (of the 16 that we analyzed) that have cancer risks 

that exceed 1 in a million. Because these cancer risk levels 

exceed the delisting criteria set forth in CAA section 

112(c)(9)(B)(i), EPA must deny UARG’s delisting petition. 

Although this fact alone is enough to determine that EGUs cannot 

be delisted under CAA section 112(c)(9), EPA also conducted a 

national-scale mercury assessment in connection with the 

development of its appropriate and necessary determination for 

this final rule. The results of this assessment are described 

fully in the preamble above and in the Technical Support 

Document accompanying this rule. The results of that assessment 

show that there are a significant percentage of watersheds that 

have populations potentially at risk from exposure to Hg 

emissions from U.S. EGUs. Specifically, up to 29 percent of the 

modeled watersheds have populations that are potentially at-risk 

from exposure to Hg from U.S. EGUs. Additionally, in up to 24 

percent of the modeled watersheds, populations are potentially 

exposed to Hg at levels greater than the RfD and U.S. EGUattributable Hg deposition accounts for 5 percent or more of 

total deposition to those watersheds. U.S. EGUs were also found 

to contribute to potential exposures greater than the RfD in 10 

percent of modeled watersheds, even excluding consideration of 

other U.S. and non-U.S. sources of Hg deposition. Since these 
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mercury impacts from U.S. EGUs “exceed a level which is adequate 

to protect public health with an ample margin of safety,” the 

delisting criterion set forth in CAA section 112(c)(9)(B)(ii), 

EPA believes the delisting petition should be denied under that 

prong of section 112(c)(9) as well.

In considering the impacts of HAP that may cause cancer in 

humans, our analyses show that HAP emissions from a subset of 

U.S. EGUs result in cancer risks above 1 in one million, thereby 

requiring EPA to deny UARG’s delisting petition. 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, pointing to the analysis supporting 

UARG’s petition as being the more correct analysis. The EPA 

disagrees with these comments, as noted below and in the more 

detailed responses to those comments provided above.

First, EPA’s analysis of the UARG petition shows that UARG 

based its own inhalation risk analyses on inappropriately 

underestimated HAP emissions, particularly non-Hg metal HAP 

emissions (refer to Appropriate and Necessary section on non-Hg 

HAP emissions for further discussion). In reviewing UARG’s 

underlying HAP emission estimates, we identified significant 

errors and low bias in the non-Hg HAP metals emissions used by 
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the petitioner. In particular, the petitioner’s analysis was 

based on Cr(VI) emission estimates that ignored a majority of 

the highest Cr(VI) measurement data obtained through the EPA’s 

ICR process, claiming that these data should be eliminated based 

on a statistical outlier test. The EPA re-analyzed the Cr(VI) 

data using an appropriate statistical outlier test (different 

from the outlier test used by the petitioners), and ultimately 

determined that the high Cr(VI) emission measurements must be 

considered. Although UARG did use EPA models to conduct its 

analysis, the emission values used in their non-Hg HAP 

inhalation analyses were not appropriately derived. Thus, UARG’s 

assertion that their “analysis is consistent with EPA guidance 

and therefore has to be accepted as valid” is incorrect.

Second, we re-analyzed the 16 case studies that we 

conducted for the proposal and revised those analyses consistent 

with new non-Hg HAP emissions data and corrected stack 

parameters provided by commenters (including UARG) during the 

comment period on the proposed rule. We received and 

incorporated revised information on stack heights and stack 

diameters for some of the case study EGU facilities, and further 

revised emissions based on the re-analysis described in the 

above paragraph. When completed, we determined that the 

corrections incorporated into the reanalysis had little effect 
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on the overall results. In the final rule, we conclude that the 

maximum individual inhalation cancer risks for 6 out of the 16 

case study EGU facilities are greater than 1 in a million.

In addition to its analysis of inhalation risks due to HAP 

from U.S. EGUs, UARG conducted a refined multi-pathway risk 

assessment for emissions of Hg and several other HAP from a 

single model EGU facility to support its petition. In 

interpreting the results of this case study, UARG calculates a 

maximum individual cancer risk estimate of 4 in a million driven 

by the ingestion of arsenic emissions from the model EGU 

facility that have deposited out of the atmosphere. Since this 

maximum risk level is too high to satisfy the delisting 

criterion that cancer risks cannot be greater than 1 in a 

million, UARG dismisses the result, stating that its modeling 

approach is “overly conservative,” even after acknowledging that 

its fictional model plant scenario was not designed to capture 

the highest potential multi-pathway risks from any EGU, and that 

the methods used to develop the risk estimates were based on 

refined models and data. The EPA believes that the results of 

UARG’s refined modeling support our analyses showing that some 

U.S. EGUs in fact are responsible for cancer risks above 1 in a 

million. Thus, we disagree with UARG’s dismissal of the results 
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of its own refined analysis, and believe that these analyses are 

further support for our denial of the UARG petition.

The UARG also claimed that EPA’s national-scale Hg analysis 

is not relevant to the delisting question, arguing that the 

statute only requires a facility-by-facility assessment of 

risks. As noted above, EPA appropriately assessed the risks of 

Hg emissions associated with the EGU source category and 

concluded that even assessing EGU Hg emissions alone, UARG does 

not meet the requirements of 112(c)(9)(B)(ii).

For these reasons, EPA believes that the national-scale Hg 

analysis demonstrates non-cancer risks from U.S. EGUs that 

support our denial of this petition.

For all the reasons described above, EPA is denying UARG’s 

petition to delist EGUs under CAA section 112(c)(9).

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 for this final rule is the 

collection of coal- and oil-fired EGUs within a single 
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contiguous area and under common control. A new affected source 

is a coal- or oil-fired EGU for which construction or 

reconstruction began after May 3, 2011.

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, 

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 
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Page 327 of 984

consecutive calendar years or for more than 15.0 percent of the 

annual heat input during any one calendar year, the unit is 

considered to be oil fired under this final rule. As noted 

below, the EPA is finalizing 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 a requirement that the unit fire coal or oil (or 

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 to be considered a “fossil fuel-fired” 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 either an 

EGU co-fires limited amounts of coal or oil with natural gas or 
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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?

This final rule regulates HCl (for oil-fired EGUs and as a 

surrogate for acid gas HAP for coal-fired EGUs) and HF (for oilfired EGUs), 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 non-mercury HAP 

metals for coal-fired EGUs or as a surrogate for total HAP 

metals for oil-fired EGUs), with total non-mercury HAP metals 

and individual non-mercury HAP metals as alternative equivalent 

standards, Hg, and organic HAP, from coal- and oil-fired EGUs.

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

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 six subcategories, 

two for coal-fired EGUs, one for coal- and solid oil-derived 

IGCC EGUs, and three for oil-fired EGUs, which we developed 

based on unit type and geographical location.

TABLE 3. EMISSION LIMITATIONS FOR COAL-FIRED AND SOLID OILDERIVED FUEL-FIRED EGUS
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Subcategory Filterable 

particulate 

matter

Hydrogen 

chloride

Mercury

Existing Unit 

designed for 

coal >8,300 

Btu/lb

3.0E-2

lb/MMBtu 

(3.0E-1

lb/MWh)

2.0E-3

lb/MMBtu

(2.0E-2 

lb/MWh)

1.2E0 lb/TBtu

(2.0E-2

lb/GWh)

Existing Unit 

designed low 

rank, virgin 

coal

3.0E-2 

lb/MMBtu 

(3.0E-1 

lb/MWh)

0.0020 

lb/MMBtu

(0.020 

lb/MWh)

1.1E1 lb/TBtu

(2.0E-1

lb/GWh)

4.0E0

lb/TBtua

(4.0E-20 

lb/GWha)

Existing - IGCC 4.0E-2

lb/MMBtu 

(0.30 lb/MWh)

5.0E-4

lb/MMBtu 

(3.0E-3

lb/MWh)

2.2E0 lb/TBtu

(2.0E-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-4

lb/GWh)

New unit 

designed for 

coal > 8,300 

Btu/lb

7.0E-3 lb/MWh 4.0E-1 lb/GWh 2.0E-4 lb/GWh

New unit 

designed for 

low rank virgin 

coal

7.0E-3 lb/MWh 4.0E-1 lb/GWh 4.0E-2 lb/GWh

New – IGCC 7.0E-2

lb/MWhb

9.0E-2

lb/MWhc

3.0E-3

lb/MWhd

3.0E-3

lb/GWhe

New – Solid 

oil-derived 

2.0E-2 lb/MWh 3.0E-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
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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 

PM

Hydrogen 

chloride

Hydrogen 

fluoride

Existing – Liquid oilcontinental 3.0E-2

lb/MMBtu

(2.0E-1

lb/MWh)

3.0E-4

lb/MMBtu

(4.0E-3

lb/MWh)

2.0E-4

lb/MMBtu

(2.0E-3

lb/MWh)

Existing – Liquid oilnon-continental 3.0E-2

lb/MMBtu

(3.0E-1

lb/MWh)

2.0E-4

lb/MMBtu

(3.0E-3

lb/MWh)

6.0E-5

lb/MMBtu

(5.0E-4

lb/MWh)

New – Liquid oil -

continental

7.0E-2

lb/MWh

5.0E-4

lb/MWh

5.0E-4

lb/MWh

New – Liquid oil -

non-continental

2.0E-1

lb/MWh

3.0E-3

lb/MWh

5.0E-4

lb/MWh

We are also finalizing alternate equivalent emission 

standards (for certain subcategories) to the proposed surrogate 

standards in three areas: SO2 (in addition to HCl), individual 

non-mercury metals (for PM), and total non-mercury metals (for 

PM). The proposed 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 Coalfired 

EGUs

IGCC Liquid 

oil, 

continen

tal 

Liquid 

oil, 

noncontinen

tal 

Solid 

oilderived

SO2 0.20 

lb/MMBtu 

NA NA NA 0.30 

lb/MMBtu 
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(1.5 

lb/MWh)

(2.0 

lb/MWh)

Total nonmercury

metals

0.000050 

lb/MMBtu

(0.00050 

lb/MWh)

0.000050 

lb/MMBtu

(0.00030 

lb/MWh)

a a 0.000040 

lb/MMBtu 

(0.6 

lb/GWh)

Antimony, 

Sb

0.60 

lb/TBtu

(0.0060 

lb/GWh)

0.40 

lb/TBtu

(0.0040 

lb/GWh)

0.30 

lb/TBtu

(0.0030 

lb/GWh)

2.2

lb/TBtu

(0.020 

lb/GWh)

0.090 

lb/TBtu

(0.00080 

lb/GWh)

Arsenic, As 1.1 

lb/TBtu

(0.020 

lb/GWh)

1.2 

lb/TBtu

(0.020 

lb/GWh)

0.50 

lb/TBtu

(0.007 

lb/GWh)

4.3

lb/TBtu

(0.080 

lb/GWh)

0.30 

lb/TBtu

(0.0050 

lb/GWh)

Beryllium, 

Be

0.20 

lb/TBtu

(0.0020 

lb/GWh)

0.030 

lb/TBtu

(0.00030 

lb/GWh)

0.060 

lb/TBtu

(0.00070 

lb/GWh)

0.60 

lb/TBtu

(0.0030 

lb/GWh)

0.050 

lb/TBtu

(0.00050 

lb/GWh)

Cadmium, Cd 0.30 

lb/TBtu

(0.0030 

lb/GWh)

0.20 

lb/TBtu

(0.0020 

lb/GWh)

0.20 

lb/TBtu

0.0020 

lb/GWh)

0.30 

lb/TBtu

(0.0030 

lb/GWh)

0.30 

lb/TBtu

(0.0040 

lb/GWh)

Chromium, 

Cr

2.8 

lb/TBtu

(0.030 

lb/GWh)

2.9 

lb/TBtu

(0.020 

lb/GWh)

1.8 

lb/TBtu

0.030 

lb/GWh)

31

lb/TBtu

(0.30 

lb/GWh)

0.8 

lb/TBtu

(0.020 

lb/GWh)

Cobalt, Co 0.80 

lb/TBtu

(0.0080 

lb/GWh)

1.2

lb/TBtu

(0.0040 

lb/GWh)

1.0 

lb/TBtu

0.020 

lb/GWh)

113

lb/TBtu

(1.40 

lb/GWh)

1.1 

lb/TBtu

(0.020 

lb/GWh)

Lead, Pb 1.2 

lb/TBtu

(0.020 

lb/GWh)

0.00020 

lb/MMBtu

(0.0030 

lb/MWh)

2.3 

lb/TBtu

0.030 

lb/GWh)

4.9

lb/TBtu

(0.080 

lb/GWh)

0.80 

lb/TBtu

(0.020 

lb/GWh)

Manganese, 

Mn

4.0 

lb/TBtu

(0.050 

lb/GWh

2.5 

lb/TBtu

(0.020 

lb/GWh)

2.9 

lb/TBtu

0.040 

lb/GWh)

20 

lb/TBtu

(0.30 

lb/GWh)

2.3 

lb/TBtu

(0.040 

lb/GWh)

Mercury, Hg NA NA 0.060 

lb/TBtu

(0.00080 

lb/GWh)

0.040 

lb/TBtu 

(0.00040 

lb/GWh)

NA

Nickel, Ni 3.1 

lb/TBtu

(0.040 

lb/GWh)

4.2 

lb/TBtu

(0.050 

lb/GWh)

5.6 

lb/TBtu

(0.070 

lb/GWh)

465 

lb/TBtu

(4.1

lb/GWh)

9.0 

lb/TBtu

(0.2 

lb/GWh)
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Selenium, 

Se

5.0 

lb/TBtu

(0.060 

lb/GWh)

22.0 

lb/TBtu

(0.20 

lb/GWh)

1.2 

lb/TBtu

(0.020 

lb/GWh)

9.8

lb/TBtu

(0.20 

lb/GWh)

1.2 

lb/TBtu

(0.020 

lb/GWh)

NA = Not applicable

a Includes Hg.

TABLE 6. ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OILFIRED EGUS

Subcategory Coalfired 

EGUs

IGCCa Liquid 

oil, 

continen

tal, 

lb/GWh

Liquid 

oil, 

noncontinen

tal, 

lb/GWh

Solid 

oilderived

SO2 0.40 

lb/MWh

NA NA NA 0.40 

lb/MWh

Total nonmercury 

metals

0.000020 

lb/MWh

0.00030 

lb/MWh

b b 0.00060 

lb/MWh

Antimony, 

Sb

0.00020 

lb/GWh

0.010 

lb/GWh

0.0020 0.0080 0.00090 

lb/GWh

Arsenic, As 0.00080 

lb/GWh

0.0080 

lb/GWh

0.0020 0.060 0.0020 

lb/GWh

Beryllium, 

Be

0.000060 

lb/GWh

0.000090 

lb/GWh

0.00070 0.0030 0.000080 

lb/GWh

Cadmium, Cd 0.00040 

lb/GWh

0.0010 

lb/GWh

0.00040 0.0020 0.0070 

lb/GWh 

Chromium, 

Cr

0.0070 

lb/GWh

0.030 

lb/GWh

0.020 0.0020 0.0060 

lb/GWh

Cobalt, Co 0.00080 

lb/GWh

0.0030 

lb/GWh

0.0060 0.020 0.0020 

lb/GWh

Lead, Pb 0.0030 

lb/GWh

0.0060 

lb/GWh

0.0060 0.30 0.020 

lb/GWh

Mercury, Hg NA NA 0.00010 0.00040 NA

Manganese, 

Mn

0.0040 

lb/GWh

0.020 

lb/GWh

0.030 0.020 0.0070 

lb/GWh 

Nickel, Ni 0.0040 

lb/GWh

0.020 

lb/GWh

0.040 4.1 0.0070 

lb/GWh

Selenium, 

Se

0.00030 

lb/GWh

0.30 

lb/GWh

0.0040 0.020 0.00090 

lb/GWh

NA = Not applicable

a Based on best-performing similar source

b Includes Hg.
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As noted elsewhere in this preamble, we are also finalizing 

a compliance assurance option that would allow you to develop 

and submit for approval a site-specific liquid oil fuel moisture 

limit and sampling plan for those EGUs that combust liquid oil 

transported in contact with seawater as an alternate to the HCl 

and HF emission limits for both liquid oil subcategories (i.e., 

continental and non-continental).

We are finalizing that new or existing EGUs are “coalfired” if they combust coal and meet the final definition of 

“fossil fuel-fired.” We are finalizing that an EGU is considered 

to be a “coal-fired unit designed for coal greater than or equal 

to 8,300 Btu/lb” if the EGU: 1) combusts coal; 2) meets the 

final definitions of “fossil fuel-fired” and “coal-fired 

electric utility steam generating unit;” and 3) is not a coalfired EGU in the “unit designed for low rank, virgin coal”

subcategory. We are finalizing that the EGU is considered to be 

a “unit designed for low rank, virgin coal” if the EGU: 1) 

combusts coal; 2) meets the final definitions of “fossil fuelfired” and “coal-fired electric utility steam generating unit;”

and 3) 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 
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coal.

We are finalizing that the EGU is considered to be an IGCC 

unit if the EGU: 1) combusts a synthetic gas derived from 

gasified coal or solid oil-derived fuel (e.g., petroleum 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 are very 

similar.297

We are finalizing that the EGU is considered to be “liquid 

oil - continental” if the EGU is not a coal-fired EGU and burns 

liquid oil, meets the final definitions of “oil-fired electric 

utility steam generating unit” and “fossil fuel-fired,” and is 

located in the continental United States (U.S.). We are 

finalizing that the EGU is considered to be “liquid oil – noncontinental” if the EGU is not a coal-fired EGU and burns liquid 

oil, meets the final definitions of “oil-fired electric utility 

steam generating unit” and “fossil fuel-fired,” and is located 

outside continental North America. We are finalizing that the 

 

297 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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EGU is considered to be “solid oil-derived fuel-fired” if the 

EGU is not a coal-fired EGU and burns solid oil-derived fuel 

(e.g., petroleum coke), and meets the final definitions of “oilfired electric utility steam generating unit” and “fossil fuelfired.”

Pursuant to CAA section 112(h), we are finalizing a work

practice standard for organic HAP, including emissions of 

dioxins and furans, from all subcategories of EGUs. The work 

practice standard being finalized requires the implementation of 

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.

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 
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determined that this beyond-the-floor level was achievable after 

considering the relevant CAA section 112(d)(2) considerations.

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 measurement of filterable PM as a surrogate for the 

total metallic HAP and finalizing measurement of HCl and HF.

In addition, we are finalizing alternative standards for 

certain subcategories: 1) SO2 (as an alternative equivalent to 

HCl for all subcategories with add-on FGD systems); 2) 

individual non-mercury metallic HAP (as an alternate to 

filterable PM for all subcategories except liquid oil-fired); 3) 

total non-mercury metallic HAP (as an alternate to PM for all 

subcategories); 4) individual metallic HAP (as an alternate to 

total metal HAP) for the liquid oil-fired subcategory; and 5) 

fuel moisture less than 1 percent coupled with tune ups (as an 

alternate to HCl and HF) for the liquid oil-fired subcategory. 

These alternative proposed standards are discussed elsewhere in 

this preamble.

E. What are the requirements during periods of startup, 

shutdown, and malfunction?
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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, in 

fact, 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 

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 
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comment on the proposed approach described above and 

whether the values we are proposing are appropriate.

Thus, 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. Specifically, the default values 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 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 
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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, we 

received CEMS data from seven EGUs that represent measurements 

made during startup and shutdown operations. These data were 

submitted in response to the requirement in the ICR to provide 

all available data from the five years prior to the date the ICR 

was issued. None of the data for startup and shutdown submitted 

by these seven EGUs meet our data quality requirements. Thus, we 

have no data on emissions that occur during startup and shutdown 

on which to set emission standards. We are therefore 

establishing work practices 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 routine, normal 

operations. We maintain that the standards as promulgated 

account for any variability in emissions that may occur during 

these periods, particularly over a 30 day averaging period, and 

commenters have provided no data that causes us to doubt that 
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determination. For these reasons, 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 provide the following 

clarification. For purposes of this rule, “startup” refers only 

to a cold startup (i.e., starting from the point of no fuel 

being fired in the boiler and the boiler at ambient 

temperature). “Shutdown” refers only to an event that ends at 

the point of no fuel being fired in the boiler. These 

interpretations are wholly consistent with the definitions of 

“startup” and “shutdown” contained in the part 63 General 

Provisions. In addition, the definition in the final rule states 

that startup ends when the turbine-generator is synchronized to 

the grid, and shutdown begins when the turbine-generator is 

disconnected from the grid. We believe these additional 
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interpretations address the comments and are rational based on 

the fact that EGUs function to provide electricity to the grid 

and, therefore they should be considered to be operating 

normally at all times electricity is flowing to the grid. 

As for the work practices, in this final rule, the EPA is 

requiring sources to operate using either natural gas or 

distillate oil for ignition during startup. The EPA also is 

requiring sources to operate all control devices necessary to 

meet the normal operating standards under this final rule (with 

the exception of SCRs) when coal or residual oil is fired in the 

boiler during startup or shutdown. It is the responsibility of 

the operators of EGUs to start their SCR systems appropriately 

to comply with relevant standards applicable during normal 

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. 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.

As mentioned earlier, periods of startup, normal 

operations, and shutdown are all predictable and routine aspects 
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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 

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 
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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 

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 
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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 is a reasonable interpretation of the 

statute. 

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 
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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 

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 C.F.R. 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 C.F.R. 63.2 (sudden, infrequent, 

not reasonable preventable and not caused by poor maintenance 

and or careless operation). For example, to successfully assert 
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the affirmative defense, 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 

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 included an affirmative defense in the final rule 

in an attempt to balance a tension, inherent in many types of 

air regulation, to ensure adequate compliance while 

simultaneously recognizing that despite the most diligent of 
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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 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 many 

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.
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Cir. 1973). Though intervening case law such as Sierra Club v. 

EPA and the CAA 1977 amendments undermine 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 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 both ensure 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. 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 

tests to demonstrate compliance with all applicable emission 

limits. For units using certified continuous emissions 
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monitoring systems (CEMS) that directly measure the 

concentration of a regulated pollutant under final 40 CFR Part

63, subpart UUUUU (e.g., Hg CEMS (for simplicity of reference, 

in other places this preamble often refers to both an Hg CEMS 

and a sorbent trap monitoring system as an Hg CEMS)), HCl CEMS, 

HF CEMS, SO2 CEMS (where an SO2 limit applies as the alternative 

equivalent surrogate for the acid-gas HAP, including HCl), 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 after 

the compliance date. For other units, the owner or operator of 

an affected unit must perform the initial performance testing in 

accordance with established EPA reference test methods or the 

Ontario Hydro method for Hg (ASTM D6784-02). You, as the owner 

or operator of an affected unit, must conduct the 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 Method 5 PM emissions testing 

to determine initial compliance. 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. Note for this rule that the 
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filter temperature for each Method 29 or 5 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 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 

monitoring system in the first 30 boiler operating days after 

the compliance date. 

(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 first 30 boiler operating days of certified SO2 CEMS 

data after the compliance date 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 
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and use an HCl CEMS for compliance, you need not conduct an 

initial stack test for HCl. Instead, the first 30 boiler 

operating days of certified HCl CEMS data are used to determine 

initial compliance. For units not using the SO2 or HCl CEMS 

options, you must conduct an initial stack test using Method 26, 

26A, or 320 testing for hydrochloric acid. You may use EPA 

Method 26 or 320 if no entrained water droplets exist in the 

exhaust gas but you must use Method 26A if entrained water 

droplets exist in the exhaust gas.

(4) For liquid oil-fired units, you must conduct initial 

performance testing as follows. For non-mercury HAP metals, use 

EPA Method 29. If you elect to meet the filterable PM limit 

instead of the non-mercury metals limit (total or individual), 

then use Method 5 maintained at 160o ± 14oC (320o ± 25oF). For 

Hg, conduct emissions testing using EPA Method 29 or 30B or ASTM 

Method D6784-02. For acid gases, conduct HCl and HF testing 

using EPA Method 26A, 320, or 26; or you may elect to use an HCl 

CEMS and/or an HF CEMS; or you may choose to measure fuel 

moisture daily if fuel is delivered continuously or per shipment 

if fuel is delivered on a batch basis or via fuel supplier 

certification. If you use a CEMS, then use the first 30 boiler 

operating days of certified CEMS data to determine initial 

compliance.
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(5) For all required performance stack tests, you must 

conduct concurrent oxygen (O2) or carbon dioxide (CO2) emission 

testing using EPA Method 3A and then use an appropriate 

equation, selected from among Equations 19–1 through 19–9 in EPA 

Method 19, 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 are required or 

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, 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 Hg 

emissions limit or less than 22 pounds of Hg per year. If your 

unit qualifies as an LEE, you must conduct subsequent 

performance tests on an annual basis 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 no significant changes have occurred,
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b. Tests were conducted using methods allowed in this rule,

c. Test sample volume or duration was consistent with that 

required in this rule, and

d. You have and maintain a complete set of documentation 

needed to electronically file results.

Under the final rule, you may elect to comply with an 

optional operating limit for PM that will be established during 

the initial compliance performance test. You may elect to use a 

PM continuous parameter monitoring system (PM CPMS) to 

demonstrate compliance with an operating limit. The PM CPMS 

operating 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 is required 

as part of demonstrating continuous compliance with a filterable 

PM, total non-mercury HAP metals, or individual non-mercury HAP 

metals limit. 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 nonmercury HAP metals. As noted below, when you use this operating 
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limit, you can reduce stack testing frequency to demonstrate 

ongoing compliance.

For dioxins and furans and non-dioxin/furan organic HAP, 

you must submit documentation that you have conducted a 

combustion process tune-up, a thorough equipment inspection, and 

an optimization service, all meeting the requirements of this 

final rule. The work practice 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 may collect 

CO and NOX data and use handheld portable analyzers or similar 

devices to monitor and verify the results. 40 CFR section 

63.10021 of the final rule addresses specific details.

For Hg, non-mercury metals HAP, acid gas HAP, dioxins and 

furans, and non-dioxin/furan organic HAP from a liquid oil-fired

EGU that has an annual capacity factor on oil of less than 5 

percent of its maximum or nameplate heat input, whichever is 

greater, you must demonstrate initial compliance by conducting 

at least every 36 months (48 months if a neural net is employed) 

a combustion process tune-up, a thorough equipment inspection, 

and an optimization service, all meeting the requirements of 
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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 may collect CO and NOX data and use handheld 

portable analyzers or similar devices to monitor and verify the 

results.

G. What are the continuous compliance requirements?

To demonstrate continuous compliance with the emission 

limitations, the final rule includes the following requirements:

(1) Where a CEMS (including a sorbent trap monitoring 

system) is used for demonstrating initial compliance, you also 

must use the CEMS on a continuous basis to demonstrate ongoing 

compliance. You must calculate a rolling average for each 

successive 30 boiler operating day period. All valid data 

collected during each successive period will be used to 

demonstrate compliance. There is no numerical minimum data 

availability required to constitute a valid 30-day rolling 

average. You must operate, maintain, and quality assure the CEMS 

in accordance with the provisions in 40 CFR section 63.10010 and 

Appendix A and B of the final rule or in accordance with 40 CFR 

Part 75, as applicable.
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For each unit using HCl, HF, SO2, or Hg CEMS for continuous 

compliance, you must install, certify, maintain, operate and 

quality-assure the additional CEMS (e.g., CEMS that measure 

oxygen 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, because almost all coal-fired utility units already 

have the necessary monitors in place under the ARP.

For HCl and HF CEMS, this rule requires use of performance 

specification (PS) 15 and Procedure 1 for certification and 

ongoing compliance. In addition, we expect to promulgate a 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 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 operating days, and 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 
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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 (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 QA test requirements 

and the applicable performance criteria, which are consistent 

with those published in support of CAMR. For sorbent trap 

monitoring systems, a RATA is required for initial 
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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 vacated Appendix K to 

Part 75. The 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.

(2) If you demonstrate initial compliance on the basis of a 

stack test (e.g., as oil-fired units are required to do for Hg), 

you must demonstrate continuous compliance by conducting 

periodic stack tests on a monthly basis for PM, non-mercury HAP 

metals, and HAP metals from coal-fired and liquid oil-fired EGUs 
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or on a quarterly basis for HCl and HF from liquid oil-fired 

EGUs with the following certain exceptions:

a. If you use a PM CPMS and associated operating limit, you 

must conduct the applicable Method 5 or Method 29 test once 

annually and re-establish 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 requirements 

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 operating day period. 

The 30-day average is calculated by all of the valid hourly 

average PM CPMS output values collected for the 30 boiler 

operating days. 

b. If you combust liquid fuels and if your fuel moisture 

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 
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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 

monitor acid gas control device parameters continuously or

ii. use an HCl CEMS and/or HF CEMS.

c. If your existing unit qualifies as an LEE for Hg, you 

must conduct a 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 

22 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. If LEE status is lost for 

a solid fuel unit, you must commence quarterly testing until you 

install, certify, and operate a Hg CEMS or sorbent trap monitor, 

and you must complete the installation and certification within 

6 months of losing LEE status; for a liquid fuel unit, you must 

commence quarterly testing.

d. If a liquid oil-fired EGU has an annual capacity factor 

on oil of less than 5 percent of its maximum or nameplate heat 

input, whichever is greater, you must demonstrate continuous 
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compliance with the applicable limits (e.g., Hg, non-mercury HAP 

metals, acid gas HAP, dioxin and furan, and non-dioxin/furan 

organic HAP limits) by conducting at least every 36 months (48 

months if a neural net is employed) a combustion process tuneup, a thorough equipment inspection, and an optimization 

service, 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 may collect CO and NOX data and use handheld 

portable analyzers or similar devices to monitor and verify the 

results. 40 CFR section 63.10021 of the final rule addresses 

specific details. In addition, you must record boiler 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 pollutant to 
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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. 

3. For the performance tune-up work practice requirement 

for organic HAP control, you must demonstrate continuous 

compliance by conducting the work practice at least every 36 

months (48 months if a neural net 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 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 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 
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General Provisions include specific requirements for 

notifications, recordkeeping, and reporting. You must submit a 

notification of compliance status report for each unit, as 

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, for 

semiannual reporting periods, 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 Part 75-based Emissions Collection and 

Monitoring Plan System (ECMPS) reporting emissions and related 

data for units using CEMS. Also as discussed below, for the PM 

CPMS and performance test results, we will require you to use 

EPA’s WebFIRE database for reporting. 

This rule will require records to demonstrate compliance 

with each emission limit and work practice standard. The General 

Provisions to 40 CFR Part 63 specify these recordkeeping 

requirements, and Table 8 of this final rule identifies them. 

You must keep the following records:

(1) All reports and notifications submitted to comply with 
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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) Fuel moisture content of liquid fuel, if you elect to 

demonstrate compliance using that information.

(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 monitoring plans developed 

for this rule as specified in 40 CFR 63.8(e), if applicable.

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.
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(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), 

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 transmittal 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 this rule. 

We are requiring that certain reports required to be 
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submitted in this rule would be submitted electronically. These 

reports would include all performance test reports, notification 

of compliance status reports, compliance, and continuous 

monitoring data summaries specified in 40 CFR part 63, 

“§63.10031 What reports must I submit and when?” Performance 

tests are required to be conducted as described in §63.7 of the 

general provisions. The information and data that must be 

submitted as the performance test report is also described in 

§63.7. This information and data must be transmitted (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 and 

information requirements for the notification of compliance 

status and compliance reports are described in detail in the 

regulatory text (§63.10031) of this rule, but they essentially 

mirror the requirements in §63.6 of the general provisions. 

These reports will also be transmitted to WebFIRE using an 

electronic form found in CEDRI and through the CDX as described 

below. The continuous monitoring summaries are required to be 

transmitted quarterly in §63.10031(f)(2). The quarterly reports 

must include all of the calculated 30 day rolling average values 

derived from the PM CPMS. These reports will also be transmitted 
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to WebFIRE using an electronic form found in CEDRI and through 

the CDX as described below. 

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 would only consist of electronic 

updates to existing information in the system. Such a system 

would 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 could 

also benefit from more streamlined and accurate electronic data 

submitted to them. Electronic reporting would 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 

would also benefit the public by generating a more transparent 
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review process and increasing the ease and efficiency of data 

accessibility. Furthermore, electronic reporting would 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 would substantially reduce this burden,

because EPA would already have this 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 

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, 
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EPA would be able to ensure that emission factors, when updated, 

represent the most current range of operational practices. 

Data entry of these electronic reports would be through the 

Compliance and Emissions Data Reporting Interface (CEDRI) that 

is accessed through EPA’s Central Data Exchange (CDX) 

(www.epa.gov/cdx). Data transmitted 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 icon that corresponds to the report being 

transmitted, 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 utility in 

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 transmittal.

In cases where performance test data are to be transmitted 

to EPA, you must enter the performance test data and information 
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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 transmits a copy of 

the ERT project data file directly to WebFIRE where the data are 

made available. Where performance test reports are transmitted,

WebFIRE notifies the appropriate state, local, or tribal agency 

contact that an ERT project data file was received from the 

source. 

Transmitting performance test data electronically to the 

EPA would 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. 

In summary, in addition to supporting regulation 

development, control strategy development, and other air 

pollution control activities, having an electronic database 

populated with these reports would save industry, state, local, 

tribal agencies, and EPA significant time, money, and effort 

while also improving the quality of emission inventories and, as 

a result, air quality regulations.

I. Submission of Emissions Test Results to 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 CEMS that are 

consistent with 40 CFR Part 75 and similar to those that had 

been promulgated for the vacated CAMR regulation. You must 

report CEMS data 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. This includes 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 receive 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 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’ Part 75 bias test (which is 

required for certain types of monitors under the EPA’s 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 

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. 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 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, 

such as 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 the 

Compliance and Emissions Data Reporting Interface (CEDRI) that 

is accessed through EPA’s Central Data Exchange (CDX) 

(www.epa.gov/cdx). You must submit performance test data in the 

file format generated through use of EPA’s Electronic Reporting 

Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html) 
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within 60 days of performance test completion. Electronic data 

transmittal requirements are described in Section V.H. of this 

preamble

Other notifications and reports will be submitted in 

hardcopy form at this time.

VI. Summary of Significant Changes Since Proposal

A. Applicability

Since proposal, the EPA has made several changes to the 

applicability of this final rule. 

The EPA is revising a number of the proposed definitions 

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 
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utility power distribution system for sale is 

considered an electric utility steam generating unit. 

40 C.F.R. 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 

(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 
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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 be subject to the 

final 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
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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 

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 
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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. 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 

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 electric 

steam generating units 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 
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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 

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 
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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 

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 
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“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 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.

Oil-fired electric utility steam generating unit means an 

electric utility steam generating unit meeting the definition of
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“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.

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, oilfired, 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.

In addition to these changes, we are also revising the 

definition of “fossil fuel-fired” based on comments. We are 

revising the definition to remove the heat input equivalent of 

25 MWe 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 
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combustion thresholds of 10 percent over 3 consecutive years and 

15 percent in one year are evaluated after the compliance date 

of the final rule on a rolling basis. Commenters correctly noted 

that some coal- and oil-fired EGUs will convert their units to 

alternative fuels (e.g., natural gas or biomass) and if the 

definition was 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 onsite 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 in any 3 consecutive calendar 

years or for more than 15.0 percent of the annual heat input 

during any one calendar year after [COMPLIANCE DATE OF THE FINAL 

RULE].

We are also removing the definition of “[u]nit designed to 

burn liquid oil fuel subcategory,” revising the definition of 
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“[u]nit designed to burn solid oil fuel subcategory,” adding 

definitions for the continental and non-continental liquid oilfired EGU subcategories, and adding a definition of a limiteduse liquid oil-fired EGU as follows:

Unit designed to burn solid oil-derived fuel subcategory

means any oil-fired EGU that burns solid oil-derived fuel.

Continental liquid oil-fired subcategory means any oilfired electric utility steam generating unit that burns liquid 

oil and is located in the continental United States.

Non-continental liquid oil-fired subcategory means any oilfired electric utility steam generating unit that burns liquid 

oil and is located outside the continental United States.

Limited-use liquid oil-fired subcategory means an EGU with 

an annual oil-fired capacity factor of less than 5 percent.

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 

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 MWe). In the 
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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.298 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 could 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.

We received comment that requested the Agency provide 

provisions that would address situations where sources become or 

cease being subject to this subpart. Because 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 

 

298 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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Rule (See Final CISWI Rule, 40 CFR 60.2145). We are finalizing 

that you are subject to the requirements of this final rule at 

least 6 months following the last date you met the definition of 

an EGU subject to this final rule (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). 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) 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 immediately 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 
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applicable CAA section 129 standards.

B. Subcategories

The proposed rule subcategorized EGUs burning coal into two 

subcategories: EGUs designed for coal >8,300 Btu/lb and EGUs 

designed for low rank virgin coal. We received a number of 

comments indicating that the definition 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 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 
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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 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 
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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 

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 without adding EGUs that are properly 

included in the other subcategory.

As stated above, we believed at proposal that the boiler 

size was the cause of the different Hg emissions characteristics 
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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 

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, and there are 

other EGUs in this subcategory that are circulating fluidized 

bed (CFB) combustion units and such EGUs do not meet the height 

to depth ratio parameters in the proposed rule, nor are they 

anything like the pulverized coal 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 EPA should clarify in which subcategory a unit 

belongs when it does not burn low rank virgin coal but it 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-refuse299 or other 

 

299 It is our understanding that no unit combusts coal-refuse 
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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 

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 it is not “virgin coal” so 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 pulverized coal 

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 

 

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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not be revised in a manner that would move EGUs that we believed 

the data shows could comply with a more stringent standard into 

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 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 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 to depth 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 reason, we 

did not revise the definition to include CFB units and 

pulverized coal EGUs with a height to depth ratio greater than 

3.5.
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We eventually concluded that it was reasonable and 

advisable to continue to base the subcategory definitions at 

least in part on whether the EGUs were designed to burn and 

burned low rank-virgin coal, but that it was not appropriate to 

continue to use the height-to-depth ratio criteria because that 

approach would potentially exclude EGUs we initially 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 such factors but nothing 

in the statute prohibits such an approach and the case law 

supports it to the extent it has 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 EPA from 

subcategorizing based on a unit being designed to use and using 

a certain material input 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 
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materials if the circumstances warranted.

We considered basing the subcategory solely on a unit being 

designed to burn and burning low rank, virgin coal. We declined 

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, a unit 

on the east coast could import one truck full of low rank, 

virgin coal and burn a very small quantity of it periodically to 

meet the subcategory definition. We determined it was reasonable 

to avoid creating this potential loophole. To that end, 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 the final CSAPR that indicated that 

the longest distance any EGU that fired low rank, virgin coal 
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transports the coal it currently combusts is 40 miles. We 

believe that 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 at or near a mine containing the low rank, virgin 

coal it burns.

For these reasons, we are revising the coal-fired EGU

subcategory definitions as follows: 1) Unit designed for low 

rank, virgin coal is a unit 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; and 2) Unit designed for coal >8,300 

Btu/lb means any coal-fired EGU that is not a unit designed for 

low rank, virgin coal.” 

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, 

virgin coal from complying with the less stringent Hg emission 
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standard. We appreciate the comments that apprised us of the 

issues with our proposed definitions and provided the 

information necessary to properly define the coal-fired EGU 

subcategories. Finally, as discussed in response to comments, we 

do not believe that additional subcategorization of other coalfired EGUs is reasonable or appropriate because all other coalfired EGUs that are not designed to burn and 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 EGUs designed to burn and burning all other 

ranks of coal are able to achieve the MACT level of control for 

the >8,300 Btu/lb subcategory. 

In addition, at proposal the EPA did not have sufficient 

emissions data from non-continental liquid oil-fired EGUs upon 

which to base a subcategory and took comment on the issue. The 

EPA now has sufficient data upon which to base the subcategory 

and, therefore, is finalizing the liquid oil-fired EGU 

subcategories of “continental” and “non-continental.” Similarly, 

the EPA did not have sufficient information on limited-use 

liquid oil-fired EGUS upon which to base a subcategory and took 
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comment on the issue. Based on comments received, we are 

finalizing a subcategory for limited-use liquid oil-fired EGUs.

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. 

This final rule includes limits for those same pollutants, with 

many of the same conditions. Based on information and data 

received during the comment period, we re-ranked the best 

performing units in the MACT floor pools. Based on the new 

ranking, some of the emission limits in the final rule have 

changed from those proposed. In addition, as discussed elsewhere 

in this notice, 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 based on comments and 

our own conclusion that available test methods for condensable 

PM were limited and, for those tests conducted prior to the 

information collection requirement developed for this rule,

unreliable due to inconsistency and lack of clear documentation. 

For liquid oil-fired EGUs, based on comments received and 

corrections made to the data submitted, we have added a 

filterable PM surrogate limit in the final rule as an 

alternative equivalent surrogate standard for the total metal-
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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 as an alternate compliance 

demonstration method for liquid oil-fired EGUs for determining 

compliance with the HCl and HF limits. Direct measurement of HCl 

and HF remains as a compliance demonstration method in the final 

rule. Finally, as discussed elsewhere in this notice, we added a 

separate compliance option consisting of burner tune-ups, much 

like those required for dioxin and furan control, for those 

liquid oil-fired EGUs whose annual capacity factor on oil is 

less than 5 percent.

D. Work Practice Standards for Organic HAP Emissions

This final rule includes work practice standards for 

organic HAP, including dioxins and furans. 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 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 
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frequency. The provisions of 40 CFR section 63.10006(r) have 

been corrected to refer to 40 CFR section 63.10021(a)(16). We 

have also adjusted the language in the final rule to recognize 

the value of automated boiler optimization tools such as neuralnet 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 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 months). Initial compliance with the work 

practice standard of maintaining burners must occur within 180 

days of promulgation. The initial compliance demonstration for 

the work practice standard of conducting a tune-up may occur 

prior to the effective date, but must occur within 42 months (36 

months from the promulgation date plus 180 days) or, in the case 

of units employing neural net combustion controls, 54 months (48 

months plus 180 days). If the tune-up occurs prior to the 

effective date, 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 actions, additional 

methods for evaluating combustion effectiveness, and 

clarification on procedures for recording CO and NOX information. 
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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 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

readings.

E. Requirements during Startup, Shutdown, and Malfunction

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. For malfunctions, the EPA is finalizing the proposed 

affirmative defense language for exceedances of the numerical 

emission limits that are caused by malfunctions.

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 
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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, 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 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 are 

not 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 
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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. LEE qualification

We have significantly modified the requirements to qualify 

as an 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 initial 

compliance demonstration. Under the final rule, to qualify for 

LEE status for pollutants other than Hg a unit must pass a 

series of performance tests over a 3-year period to demonstrate 

that the unit continues to perform well below the standard.

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)) and 

periodic testing. As noted above, the final rule does not 
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contain the proposed fuel analysis requirements. For periodic 

testing, the proposed rule required testing every month or every 

two months. The final rule requires monthly PM and non-mercury 

metals HAP, whether individual or total for coal- and liquid 

oil- fired units; monthly HCl testing for coal-fired units and 

quarterly HCl and HF testing, along with continuous acid gas 

control device parameter monitoring for liquid oil-fired units. 

The final rule has a separate compliance demonstration for those 

EGUs that have an annual capacity factor of less than 5 percent. 

The continuous monitoring options remain generally intact from 

the proposed rule, with minor clarifications concerning 

calculation of 30-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 

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 rolling 30-day average basis.
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Apart from the operating limit for acid gas control devices 

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, Part 70 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. Like the PM CPMS operating limit, the operating limit 

for acid gas control devices will be set using the highest 

hourly average obtained during the HCl and HF performance test. 

Compliance with the limit is based on a rolling 30-day 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 
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optimization. Based on the comments received, we have reduced 

the required frequency for this inspection and provided 

incentives for neural network combustion management and 

optimization practices by providing a longer interval between 

inspections when such systems are in use at a given EGU.

H. 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 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 CEMS data, the final rule requires 

electronic reporting of certain data, including performance test 

reports and PM CPMS 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 
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adopting these approaches. In the final rule, we have extended 

the ECMPS reporting to all CEMS data to promote harmonization 

for CEMS data from the industry, while leaving reporting of nonCEMS data in a separate reporting system.

I. 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 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.
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Response: The EPA has incorporated all 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 standards 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

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 
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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. 

However, Congress limited the EPA’s authority to parse units and 

sources with similar design and types but 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 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 
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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 

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 
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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 

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 

re-begs 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 of course reflect sources’ actual 

performance and were achieved in practice. As to commenters’
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claims that standards set in this manner cannot be met by any 

actual sources, we have determined that there are approximately 

64 existing 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.

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

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 
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– that is floors reflecting mediocre or no control, rather than 

performance which is the average of what best performers have 

achieved. See 61 FR at 173687 (April 19, 1996); 62 FR at 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 

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, the floor for acid gases or metals would end 

up not reflecting best performance. In such a situation, the EPA

would have to make some type of value judgment as to which 

pollutant reductions are most critical to decide which sources 

are best controlled.300 Such value judgments are antithetical to 

 

300 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 
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the direction of the statute at the MACT floor-setting 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 

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

 

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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effectuates statutory goals and policies in a reasonable manner, 

its interpretation must be upheld. See Chevron v. NRDC, 467 U.S. 

837 (1984).301

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 

 

301 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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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 

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) 
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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 

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 this 

result 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 instead we continue to adhere 

to the clear statutory directive.

4. Treatment of Detection Levels
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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 

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 (0). 

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. 
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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 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 non-detects. 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 
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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 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.

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. 
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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 

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 

remarks for 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. On 

the contrary, some 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 
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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 

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 insure that there is only about a 1 percent 
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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, 

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 
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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

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 

arbitrarily adjusted value is expressed differently by various 

laboratories and is called limit of quantitation (LOQ), 

practical quantitation limit (PQL), or reporting limit (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 arbitrary values reflect individual 

laboratories’ perceived confidence, we decline to adopt the LOQ, 

PQL, or RL because such approached in our view would arbitrarily 

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 
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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 

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 and internal concerns 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), 
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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 

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 

as the representative detection level (RDL) as 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 before including for the 

Portland cement MACT determination. 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 
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calculated floor or emissions limit (e.g., calculated from the 

UPL), we would conclude that measurement variability was 

adequately addressed with the initial floor 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. If indicated, we substituted the value equal to 

3xRDL for the calculated floor or emissions limit 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 emissions limits 

adjusted in this manner better ensure measurement variability is 

adequately addressed relative to compliance determinations 

better than the procedure applied for the proposal that may have 

been based on data sets smaller than seven tests and as few as 

one test, as we had with several of our new source MACT floors. 
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We also believe that the emissions testing procedures and 

technologies available now and in the future will be adequate to 

provide the measurement certainty sufficient for sources to 

demonstrate compliance at the levels of the adjusted 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.
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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 also 

failed to consider or address the antagonistic effects that 

adding multiple different pollution control devices can have on 

an EGU’s HAP emissions. Commenters indicated that EGUs would not 

be able to comply with this proposed new-source 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 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 
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appropriate. Based on the revised ranking, the best performing 

source for PM changed and that source now forms the basis for 

the new-source filterable PM limit in the final rule. The source 

is an EGU that includes the entire suite of controls that would 

likely be required on a new source constructed prospectively 

(i.e., it is a unit with SCR, dry FGD, and FF), so we maintain 

that 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). 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 units should be achievable. According to the commenters, no 

existing unit is currently meeting the proposed new source 
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limits, which will result in a moratorium on the construction of 

new coal-fired units. The commenters state that this regulation 

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.
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Other commenters stated that the synergistic impact of 

multiple controls has not been taken into account in the 

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 particulate must be removed by PM control 

devices, as well as the particulate added to the flue gas for 

units 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 additional 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 standardsetting 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 
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effects of the concurrent use of various control technologies. 

For example, one commenter states that 47 of the 131 sources 

used to calculate the existing source total PM limit only had PM 

control but no acid gas or Hg controls that could also 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 commenters’ contention that the 

pollutant-by-pollutant approach to establishing MACT floors is 

inconsistent with the CAA for the reasons set forth in 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 able to meet 

the proposed 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, and we have identified at least one source that is 
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meeting all of the new-source limits in the final rule. Also, 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 complied with the statute in establishing the standards in 

this final rule and the standards are valid, notwithstanding the 

fact that the final standards are more stringent that CAA 

section 112(g) standards issued by various state agencies. 

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 a 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 

that would be constructed today (i.e., an EGU with only PM 

control and no SO2 controls); however, the final standard is not 
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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 coalfired 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 coal-fired 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 coalfired 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.

This has been done through use of the 3XMDL (discussed elsewhere 

in this preamble and the Response to Comments document) and 
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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 

contend that apart from being inconsistent with applicable MACT 

case law, counting combined stack emissions as two or more data 
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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 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. 

Indeed, the opposite is true. 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 either unit actually 

performed. One commenter also stated that in several instances 

when a facility operated tandem or multiple EGUs but only 
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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 

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 inleakage 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 

ductwork) and will report the results as being for each EGU.

The EPA has reviewed the data based on comments received 
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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. 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 dictate any specific control or methodology.

Comments were also received that some state programs 

contain Hg emission limits that are more stringent than the 
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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, 

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 
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to implement and enforce. 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. The EPA believes, however, that an 

emission rate format allows for, and promotes, the use of precombustion HAP removal processes because such practices will 

help sources assure they will comply with the proposed standard. 

Furthermore, 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 inconsistent with 

the DC Circuit’s rulings as restated in the Brick case (479 F.3d 

at 880) that 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.
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The 2010 ICR data confirm the point relating to plant 

inputs likely playing a role in emissions in that they 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 even 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. For all of these reasons, 

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 noted by 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. Commenter did not note which form of the 

standard the EGUs were meeting so it is unclear whether the 

standards are in fact more stringent. In any case, EPA is must 

comply with CAA section 112(d) when establishing standards and 

the statute does not mandate that such standards be more 
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stringent than state laws that regulate 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 sources 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 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

is obliged to have more, not less, data to support the proposed 

beyond-the-floor Hg limit for low rank coal EGUs. One commenter 
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added that the EPA’s decision to require a beyond-the-floor 

limit for the low Btu 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 beyond-the-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 believes that the data used to conduct the 

beyond-the-floor analysis are consistent with results achieved 

in U.S. DOE Hg control technology demonstration projects. The 

DOE’s National Energy Technology Laboratory (NETL) sponsored a 

project entitled “Mercury Control for Plants Firing Texas 

Lignite and Equipped with ESP-wet FGD”. In this project, URS 

Group evaluated sorbent injection for Hg control in an 85/15 

blend Texas lignite/PRB-derived flue gas. The authors of the 

final project report noted that, in short term parametric tests, 

three different brominated sorbents performed similarly with 

results indicating that 90 percent reduction of Hg was 

attainable at injection rates of 2 to 3 pounds per million 

actual cubic feet (lb/Macf) and greater than 90 percent at 

higher rates. This is also shown in Figure 3-7 of the final 

report. In longer-term (60-day) testing using a brominated 

sorbent, Hg removal averaged 80 percent at a modest injection 
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rate of 2 lb/Macf. This compares favorably to the results of 70 

to 90 percent achieved in the short-term testing at the same 

injection rates. Figure 3-12, however, predicts that greater 

than 90 percent could have been achieved at injection rates of 3 

to 5 lb/Macf. Note that all of these results are for control 

across a cold-side ESP. Control across a fabric filter is 

normally expected to exceed that measured through an ESP. (We 

would note that both fabric filters and ESPs can be effective in 

HAP control when properly designed and operated.) 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 recognizing that some EGU’s costs will be 

more and some less; EGUs whose costs are higher are not exempted 

from the regulation. Further, the EPA would note that 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 more true for beyond-the-floor 

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 
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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 

proposed a revised beyond-the-floor limit for Hg of 0.00020 

lb/GWh for all new IGCC units regardless of coal type. The limit 

was set to be the same as the new source limits for coal-fired 

EGUs designed for coal with a heat content of greater than 8,300 

Btu/lb. 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 allege that the EPA has not provided adequate 

justification of its decision from a technology capability 

assessment. Commenters note that ACI for Hg treatment of coalderived 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. Because of a lack of data, the EPA

did not propose beyond-the-floor MACT limits for existing IGCC 

units. 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 EPA’s limits for new IGCC 

sources are based on beliefs, predictions, projections and 

design target assumptions. The limits from the 2007 DOE Report 
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referenced in the preamble are based on environmental target 

assumptions. These IGCC environmental targets were chosen to 

match 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 

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 
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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 

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 
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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 

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 
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incorporate effective controls have been built and tested.

Response: The EPA is not finalizing the proposed new source 

standards. As commenters noted, EPA proposed beyond-the-floor 

limits for IGCC units based on the performance of pulverized 

coal-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 

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
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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 

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 
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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. 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. 

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 
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the commenters, the EPA did not even attempt to legitimately 

analyze this issue and, thus, 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 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 

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. 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 
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commenters also believe that as long as a control option is 

commercially available, that it may be costly 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 

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. At the 

time of the prior rule, 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. Activated carbon was only a 

fledgling and unproven technology at the time; today, however, 

activated carbon has been proven, and units burning bituminous 
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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 

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 

subcategories are warranted and has not provided any in the 

final rule. Commenters are correct in that additional 

subcategorization was proposed in January 2004. Without agreeing 

with commenters that 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 looked at in total, with the exception of Hg, the EPA

does not believe that the emissions to the atmosphere are 

sufficiently different 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 and non-mercury 

metallic HAP indicating that the MACT floor limits established 

based on these units are achievable by units burning all ranks 
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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 

subcategorizing by coal chlorine content but, in any event, the 

EPA does not believe that any fundamental discrimination between 

coal ranks will result 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 

result is consistent with the intent of CAA section 112 

standards.

The EPA agrees, in theory, that EGUs are designed around a 

basic set of coal characteristics. However, it was learned 

during the 1999 ICR 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 
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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 

any possible subcategorization approaches or that it has 

insufficient data upon which to base or evaluate various 

subcategories, and, although commenters suggested additional 

subcategories were warranted, none provided sufficient data we 

requested at proposal to support alternative subcategories. As 

noted elsewhere, the EPA does not disagree with commenters that 

there are differences in EGUs; however, the EPA does disagree 

with commenters that all of those differences result in 

differences in emissions to the atmosphere such that 

subcategorization is justified for additional subcategories. The 

EPA may not postulate or hypothesize what subcategories (or MACT 

floor levels) MIGHT be appropriate were other data to be 

available. The final limits are based on EGUs currently 

operating with available controls, indicating that the levels 

are achievable, and 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 
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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 additional subcategories.

The EPA disagrees with the commenters that suggest EPA may 

not consider material inputs when considering subcategories, 

though we do agree 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 considers fuels switching in evaluating 

potential beyond the floor 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 Btu 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 well-controlled 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, in addition, absent such a subcategory, 

about 12 percent of coal deliveries (2005 data), and the vast 
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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 is similar to those that the EPA relied upon to 

support Hg subcategory for low Btu coal. According to the 

commenter, the EPA’s key rationale for a Hg subcategory for low 

Btu coal was that no low Btu 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 
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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, 

and 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 that indicates 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 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 that demonstrates that sources 

are unable to meet the proposed HCl limit due to chlorine 

content of the coal, we believe it is unnecessary and 

inappropriate to consider subcategorizing based on chlorine 
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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 surrogate 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 a surrogate for all the acid gas HAP. If 

a source is unable to meet the SO2 limit due to the sulfur 

content of the coal, the source must comply with the HCl limit. 

Commenters have not demonstrated that they are unable to meet 

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 
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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 

spreadsheet showed that 14 of those units are FBC units. The 

commenters maintained that had FBC units performed like 

conventional PC boilers then 2 would have been expected 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 than 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 
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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 

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. 
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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 pulverized coal (PC)-

fired EGUs and FBC/CFB EGUS; however, the commenters are 

incorrect in asserting 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 
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that they were selected because of their boiler design. However, 

EGUs were not selected as best performers for Hg, as EPA did not 

select any EGUs based on a determination that they were best 

performers for Hg, and to the extent CFB units were selected 

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 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 
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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

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 
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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 elsewhere in this document, the EPA does 

not believe there is a basis for subcategorizing small EGUs, 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 newsource 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 

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 
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those found in the large unit fleet, their contribution to the 

total EGU emissions isn’t significant. The costs associated with 

coming into compliance with the proposed rule via the 

installation of new controls would be proportionally much higher 

for these small EGUs according to the commenters. The commenters 

allege that this would surely 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 

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 public power 

electric utility subcategory, rural subcategory, and many other 

fuel type subcategories. Other commenters endorsed the 
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establishment of a less than 100 MW subcategory that will reduce 

the costs of the proposed rule significantly but only affect 5 

percent of the total electric utility sector and would help 

minimize uneconomical plants from facing retirements.

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 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 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 
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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 

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, 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, such units are controlled the same as 

other, larger EGUs, such that additional subcategorization is 

not necessary or reasonable. Further, we have no reason to 
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believe that a similar analysis for HCl and PM would not show 

the same result. 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.

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 
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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 

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 upsetting 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.
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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 

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 
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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 

[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 also 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 
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standards for NESHAP should be set pursuant to CAA section 

112(d)(3).

Response: 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 it would not be appropriate to subcategorize 

units even if we believed such a subcategory was consistent with 

the statute.

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 
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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 

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 
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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 

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 
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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 its 

proposed position of no distillate vs. residual oil subcategory 

is correct. 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 missentered the data, 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 were the best-performing units for PM and the 

HAP metals. Further, although emissions of HAP from distillate 

oil-fired EGUs are generally lower than those from residual oilfired 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 and we believe it 

inappropriate to exclude distillate oil-fired EGUs from 

regulation under the final rule because the Agency did not make 
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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 

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 
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residual oil-fired units in the final rule. 

3. Limited-use Subcategory

Comment: Several commenters stated that EPA should establish a 

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, 
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the commenter believed that it is essential that it be able to 

do so.

Other commenters noted that requiring installation of 

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 would likely require 

the unit to operate on oil (and emit pollutants just for the 

test) when it would otherwise be off-line or operating on 

natural gas.

Response: 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 

preclude the ability to conduct stack testing), or be 

held to the same emission limitations (which could be 
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met through fuel sampling) as other liquid oil-fired 

units. EPA solicits comment on all of these proposed 

subcategorization approaches.

Based on the comments received, we have determined that it 

is appropriate to establish a limited-use liquid oil-fired EGU 

subcategory. There are 64 liquid oil-fired EGUs in the 2010 ICR 

database with annual oil-fired capacity factors of less than 5 

percent and 80 with annual capacity factors of less than 10 

percent. In requesting the limited-use subcategory, commenters 

specifically pointed to periods of natural gas curtailment as 

being those periods where the subcategory would be most useful. 

Although commenters indicated a prevalence of natural gas/oil 

co-fired EGUs, the EPA believes that there may be 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.

Therefore, we are establishing a limited-use subcategory 

for liquid oil-fired EGUs with an annual oil-fired capacity 

factor of less than 5 percent.

Commenters also 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 
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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, upon the 

effective date of the final rule, such testing would be 

mandatory on a yearly basis for all of the EGUs. 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.

Liquid oil-fired EGUs subject to this subcategory would be 

required to conduct an annual tune-up according to 

manufacturer’s specifications.

4. Non-Continental Units

Comment: Commenters from affected island EGUs requested that 
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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, 

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.
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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 has included such a subcategory in the final rule. At 

proposal, the EPA did not have all of the data from liquid oilfired 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 noncontinental 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 non-continental 

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.
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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 of access to alternative fuels (e.g., 

natural gas).

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 our 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: 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 
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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 

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 particulate with the uncontrolled emissions estimates 

and found that the control of metals emissions was consistent 

with the control of PM. 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 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 performance; although, measurement of the 

control of filterable particulate was nearly as good. 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 are controlled to significant

reduction levels using acid gas technologies (wet and dry 
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scrubbing). Given that the rule also provides for acid gas 

control monitoring, and the general equivalency of the different 

indicators, we opted to use a filterable PM limit for the PM 

surrogate emission limit in the final rule. Use of filterable PM 

is consistent with all other NESHAP. We believe that our 

departure to total PM was premature given the concerns with the 

measurement of total PM and indecisive correlations between HAP 

and the various PM fractions.

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. 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 
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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 acknowledges that there are no FGD systems 

installed on oil-fired 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’ notice of studies indicating one plausible 

reason for the chloride/fluoride contamination of fuel oils 

appears reasonable. Therefore, the EPA is providing alternative 

compliance approaches in the final rule to demonstrate 

compliance with the acid gas HAP standards. Specifically, 
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sources can demonstrate compliance through either specific HCl 

or HF measurements or by restrictions of the moisture content in 

the fuel oil of 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 

the following industries: Iron & Steel Foundries, Electric Arc 

Steelmaking, Coatings Operations Area Source Controls Rule, 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 said that area source rules 

would lessen the regulatory burden of a CAA section 112 EGU rule 

on many small entities (indicating 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 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 consistent with the statutory 

definition of EGU and reasonable; however, we do not believe 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 to establish GACT standards 

for area sources and we believe it may even be unreasonable to 

do so under the circumstances we identified in the proposed 

rule. For these reasons, 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 
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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 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 also failed to indicate that they in fact evaluated 

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 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 to meet other requirements. According to 

these commenters, these synthetic area sources would likely be 
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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 64 EGUs 

will be able to meet the existing source standards with their 

current control configuration.

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 in different source categories. Commenters 

have not shown that the circumstances applicable to those other 

sources categories are similar to the circumstances we 

identified for major and area source EGUs (e.g., similar 

controls, similar emission characteristics, large number of 

synthetic minor area sources), and those other source categories 

are not statutorily defined in a manner that includes both area 

and major sources. Specifically, 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 
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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 we 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’

implication 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 
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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 

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 
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for the decision. 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). Thus, 

the EPA does not believe that further documentation is required. 

All of the existing control technologies would be considered to 

be “generally available” and, thus, candidates for consideration 

under any area source determination. The EPA has not “neglected”

its discretion; it merely has opted to exercise it in a manner 

different than what commenters want. Furthermore, this was only 

one reason we determined that a GACT standard was not 

appropriate for EGUs. Despite some commenters assertions to the 

contrary, the EPA did fully consider whether it was reasonable 

to establish separate standards for area sources, whether GACT 

standards for area source EGUs would be appropriate, and what 

the potential GACT standards might be if we established such 

standards; and, based on those considerations, we exercised the 

discretion afforded the Agency under the statute and declined to 

set separate standards for area source EGUs.

E. Health-based Emission Limits
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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 expected 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 

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 
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cited regulatory precedence 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 precedence 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 

(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 

Mn. These commenters argue there are no differences sufficient 

to warrant a reversal of that decision in the EGU MACT standard. 

The commenters also raised concerns that health risk information 
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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 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.
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Co-benefits of controlling HCl 

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 

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 
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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.

Cost Impacts of HBEL

Several commenters indicated that the current economic 

climate requires the EPA to balance economic and environmental 

interests and they indicated that HBEL would help target 

investments into solving true health threats where limits are no 

more stringent 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 an HBEL.

Response: After considering the comments received, some of which 

supported adoption of an emissions standard under CAA section 

112(d)(4) and some of which opposed such a standard, the EPA has 

decided not to adopt an emissions standard based on its 

authority under CAA section 112(d)(4) in the final rule for all 

the reasons set forth in the proposed rule. 

The EPA notes that the Agency’s authority under CAA section 
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112(d)(4) is discretionary. That provision states that the EPA

“may” consider established 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.

First, 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 
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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, since the data are not available that would 

allow us to develop acid gas HBELs 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 
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not assuaged by the comments received, primarily 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 

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 
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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 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, for example in determining 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, 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 
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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 to make 

the discretionary choice to regulate certain HAP based on the 

MACT approach and whether the EPA must ignore collateral health 

and environmental benefits when choosing whether or not to 

exercise that discretion. The EPA believes there is no legal 

principle that precludes it from doing so.

F. Compliance Date and Reliability Issues

Comment: Multiple commenters asked that the compliance date be 

clearly stated as soon as possible, as well as guidance provided 

for utilities unable to comply with the stated timelines, to 

allow time for utilities to prepare. Commenters also asked that 

any decisions or policies 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 authority under CAA 

section 112(n)(1)(A); state authority under CAA section 

112(i)(3); Presidential authority under CAA section 112(i)(4); 
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categorical extension 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 

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 
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“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; Regional 

Haze; Clean Air Transport Rule; Water Effluent Limit Reductions; 

Cross State Air Pollution Rule; Industrial, Commercial and 

Institutional Boilers NESHAP; CISWI; NSPS for greenhouse gas 

emissions from EGUs; NAAQS for SO2, NO2, ozone, and PM; and Area 

source Boiler MACT) and extend the compliance period. Many 

commenters noted these other requirements and cited the fact 

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.

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 
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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 tremendous

amount of work invested in creating state-specific programs to 

curb emissions within a reasonable timeframe, protecting both 

the economic viability of the state and the health of the 

public. 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 hard-negotiated comprehensive 

state-specific programs designed to yield greater emission 

reductions than the MATS alone.

However, 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 

less than 2 years and that the electric industry is wellpositioned to comply with the EPA’s proposed air regulations 
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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 recent electricity forward capacity market 

auctions in the PJM and ISO-New England markets for the period 

of 2014 and 2015 that indicate that the capacity markets cleared 

with electricity reserve margins of 20 percent in PJM and 
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greater than 14.4 percent in ISO-New England; these reserve 

margins are well 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 the proposed climate 

legislations 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.

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 [DATE OF PUBLICATION OF THIS FINAL RULE IN THE 

FEDERAL REGISTER], whichever is later. Existing sources may be 

provided up to 3 years 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. 
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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 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 coal-fueled units as a result of this final rule (5.5 GW) are 

fewer than was estimated at proposal and much fewer than some 

have predicted. Because concerns have been raised that the use 

of DSI may not be as prevalent as the agency has predicted and 
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because this could lead to more coal retirements, the agency 

also performed a sensitivity analysis in which less DSI systems 

and more scrubber systems were installed. In that sensitivity, 

we see approximately 1 more GW of retirement. This small change 

would have only a very small potential impact on reliability. 

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, 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 
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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. For example, in August 2010, 

M.J. Bradley & Associates and the Analysis Group released a 

report commissioned by several utilities on the reliability 

impacts of the MATS and the CSAPR. Their analysis, which 

examines reserve margins, demand trends, industry’s track record 

with regard to the installation of new capacity and pollution 

control equipment, among other factors, concluded that the 

“electric industry is well-positioned to comply with EPA’s 

proposed air regulations without threatening electric system 

reliability.”

302 In June 2011, they updated the earlier report 

based on the actual MATS proposal, recent financial statements 

from industry, and recent activity in the forward markets for 

future generating capacity. This update “reaffirms the major 

 

302 M.J. Bradley & Associates and Analysis Group, August 2011, 

“Summer 2011 Update: Ensuring a Clean, Modern Electric 

Generating Fleet while Maintaining Electric System Reliability.”
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conclusion of the prior report that the electric industry can 

comply with EPA’s air pollution rules without threatening 

electric system reliability provided that EPA, the industry and 

other agencies take practical steps to plan for the 

implementation of these rules and adopt appropriate regulatory 

approaches.”

303

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.304 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 notes, as EPA 

has acknowledged, that even where there is adequate generation 

capacity on a regional basis, localized reliability issues may 

 

303 M.J. Bradley & Associates and Analysis Group, June 2011, 

“Ensuring a Clean, Modern, Electric Generating Fleet while 

Maintaining Electric System Reliability.”

304 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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emerge in connection with retirements that may need to be 

addressed.

The EPA has reviewed industry studies suggesting, contrary 

to the EPA’s and other groups’ analyses, that EPA rules 

affecting the power sector (including this final rule, the 

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 
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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 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.

Second, in reporting the number of retirements, many 

analyses fail to differentiate between plant retirements 

attributable to the EPA rules and 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.

These and other flaws in these analyses have been 
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highlighted by other studies, including the M.J. Bradley and 

Analysis Group analyses discussed above, a June 2011 report by 

the staff of the Bipartisan Policy Center,305 and an August 8, 

2011, report of the Congressional Research Service.306

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) Some 

commenters state that 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) Some 

commenters maintained that the timing of outages to install 

controls will cause short term closures that could threaten grid 

stability; (3) Some commenters state that owner/operators may 

shut down EGUs rather than invest in retrofits to keep them 

running and that these closures may cause a loss of critical 

generation; and (4) In a related manner, some commenters believe 

the construction of replacement generation or implementation of 

 

305 Bipartisan Policy Center, June 13, 2011, “Environmental 

Regulation and Electric System Reliability.” This report 

concludes, among other things, that “scenarios in which electric 

system reliability is broadly affected are unlikely to occur.” 

Id. at 3.

306 James E. McCarthy and Claudia Copeland, Congressional Research 

Service, August 8, 2011, “EPA’s Regulation of Coal-Fired Power: 

Is a ‘Train Wreck’ Coming?”
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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. 

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 

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.307 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. 

Although we do not expect to see any regional reliability 

 

307 See Technical Support Document on Resource Adequacy in this

Docket.
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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. To begin, utilities can help to assure reliability 

through proactive steps in coordination with relevant planning 

and regulatory authorities. 

First as we said in the proposal, early planning is key. 

The industry has adequate resources to install the necessary 

controls and develop the new capacity that may be required 

within the compliance time provided for in the final rule.308

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 

 

308 As stated above, EPA has provided the maximum compliance time 

authorized under CAA section 112(i)(3)(A).
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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 coordinator in 

the case of non-RTO regions), state regulatory agencies, and 

regional reliability entities as soon as possible that they will 

retire. As we said before, in most places a closing plant will 

not be a cause for concern for reliability. To the extent there 

is concern, however, early notification will provide an 

opportunity for transmission 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 close 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 
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later than 12 months after this regulation is final in order to 

allow a smooth transitioning to action to avoid a reliability 

problem. Although EPA does not have the authority to require 

such early notification, it strongly encourages it 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 

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 and could be on-line by the third quarter of 

2014.309 The EPA notes, as well, that in the 3 years from 2001 to 

2003, industry brought over 160 GW of generation on line.310

Demand side options include energy efficiency as well as 

 

309 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 DC, 

http://www.bipartisanpolicy.org/sites/default/files/Paul%20Sotki

ewicz-%20Panel%202_0.pdf, slide 6

310 {need citation}
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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.311 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 

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,312 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.313

 

311 BPC slides cited above – slide 5

312

http://www.exeloncorp.com/Newsroom/pages/pr_20091202_Generation.

aspx?k=eddystone

313 Cromby Units 1 and 2 and Eddystone Units 1 and 2 –

Deactivation Study, Updated September 7, 2010 -

http://policyintegrity.org/documents/20100907-cromby-and-
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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 established regulations to implement the 

provision and the provision applies to all NESHAP. See 40 CFR 

63.6(i)(4)(i). 

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., 

 

eddystone-retirement-study-posting-update.pdf
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when controls for one unit need to be located in an open area 

needed to construct controls on another unit). In other words, 

the additional 1-year extension would provide an additional two 

shoulder periods to schedule outages. 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 where a facility owner 

has made a clear and diligent effort to install controls within 

the 3-year time frame but is unable to complete the 

installation.

As we indicated at proposal, this category of sources is 

unique due to the large, complex and interconnected nature of 

electrical generation, transmission and distribution, and the 

criticality of the electric grid to 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 
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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 provide the fourth year for EGUs.

The EPA took comment on whether the construction of on-site 

replacement power could be considered the installation of 

controls such that the fourth year would be available for a unit 

that is retiring but necessary for reliability while the 

replacement unit is being completed (e.g., a case when a coalfueled unit is being shut down and the capacity is being 

replaced on-site by another cleaner unit such 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 the 

installation of controls such that it would be appropriate for 

permitting authorities to grant a 1-year extension beyond the 3-
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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) 

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 

based on information from the RTO or other planning coordinator 

for the relevant region, and/or NERC or one of its regional 

entities, and/or the Federal Energy Regulatory Commission (FERC) 

or the DOE, that continued operation of a particular unit slated 

for retirement for some or all of the additional year is 
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necessary to avoid a violation of applicable FERC-approved or 

state electric reliability standards. 

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 easily determine that emission controls 

are being installed or that replacement power is being 

constructed. It should also provide information to determine 

whether the company is working expeditiously to comply, and 

whether the construction schedule will nonetheless exceed the 3-

year compliance window. 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, EPA believes that Title V permitting authorities 

should be able to quickly make determinations as to when 

extensions are appropriate.
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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 from the 

relevant RTO or other planning coordinator and, where 

appropriate, the state electric regulatory agency, and/or NERC 

or its regional entities, and/or FERC – demonstrating that 

retirement of a particular unit within the 3-year compliance 

period would result in a violation of applicable FERC-approved 

or state reliability standards. 

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 

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 
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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 

both of these two 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 

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, 
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however, is similar – reductions of the existing unit’s HAP 

emissions (through retirement) while maintaining electric 

reliability. If such situations develop, permitting authorities 

should consider whether – where the reliability problem has been 

properly demonstrated, as discussed above – 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, 

transmission upgrades, or demand-side measures, within 4 years, 

is likely to be very small or nonexistent. This view is echoed 

by 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 
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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 concern. 

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 that document.

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 
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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 benefits; however, Congress provided the Agency 

limited flexibility to address such situations under CAA section 

112. The EPA would welcome discussion with states and sources 

about any specific cases.

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 – suggesting 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: 

Some have criticized EPA’s analysis that DSI is a 

viable option to control acid gas emissions, and that 

as a result EPA has underestimated the number of units 

that will need to install wet or dry FGD controls to 

meet the proposed acid gas limits. These criticisms 

are off the mark. DSI is a mature technology that

involves injecting one of a number of chemical 
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reagents, including Trona, sodium bicarbonate, and 

hydrated lime, at various points along the flue gas 

path, to react with SO3, SO2, and acid gases to capture 

the reaction products. This particular technology is 

well suited for units that burn fuels with lower or 

mid-level sulfur contents, and is among the viable 

options available for a number of sources to achieve 

the proposed HCl limits...Because DSI reagents react 

with and remove HCl before SO2, sources employing DSI 

to control SO2 have controlled for HCl (and other acid 

gases) using that technology. DSI technology may alone 

be sufficient or will go a long way toward achieving 

the limits proposed in the Rule. Thus, 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: The EPA agrees with commenters who believe that DSI 

technology is proven or 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 
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implemented trona injection for that purpose across its entire 

bituminous coal-fired fleet where both SCR and wet FGD systems 

are in place.314 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.315 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 suggested by Dominion Energy’s studies of adding DSI 

on two 625 MW units at the Kincaid plant in Illinois.316

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 

 

314 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

315 NRG Energy letter to RGGI, Inc, November 22, 2010, 

http://www.rggi.org/docs/NRG_Nov_2010.pdf

316 Dominion Energy, BART Analysis for the Kincaid Power Plant, 

January 2009, http://www.epa.state.il.us/air/drafts/regionalhaze/bart-kincaid.pdf
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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. 

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 
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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 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 
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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, 

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 DOE and the EPA have engaged in discussion and evaluation of 

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.317 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, 

 

317 Solvay Chemicals, Inc, Pilot Plant Study of HCl and SO2 

Removal from CAPP Coal - Latest Results of Dry Sorbent Injection 

with Sodium Sorbents, October 2011, 

http://www.solvair.us/static/wma/pdf/1/9/3/3/7/Dry_Injection_of_

Trona_or_Sodium_Bicarbonate_for_Multi-Emissions_Control.pdf.
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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 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 

Conveyor318 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 re-analyze 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 

 

318 United Conveyor Corporation, Dry Sorbent Injection for 

Simultaneous SO2, HCl, and Hg Removal, October 2011, 

http://unitedconveyor.com/dsi/
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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 

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, 
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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 

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,319 an option not modeled in IPM, 

 

319 TW Lugar, et al., The Ultimate ESP Rebuild: Casing Conversion
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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 

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 a {$xyz,000 

(ab percent)} increase in the projected cost of the rule.

 

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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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 

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 2010.320,321 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.

 

320 http://www.wma-minelife.com/trona/tronmine/tronmine.htm

321 http://www.wmaminelife.com/trona/TronaPage2/trona_production.htm
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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.

2. Economic Hardship

a. Job losses and economic impacts.

Comment: Several commenters indicated that 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 coal-fired plants 

in the Southeast especially will mean the loss of high-paying, 

high-skilled jobs and drastic price increases in energy costs. 
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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 and has updated its analysis to reflect the final 

MATS. The Agency estimates the annual costs of the final rule in 

2015 to be $9.2 billion in 2007 dollars. The estimate of early 

retirements of coal-fired units is 5.5 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 the rule. 

EPA estimates that there will be an increase of 3.0 percent in 

retail electricity price on average nationwide in 2015 as an 

outcome of this rule, with the range of increases from 1.3 

percent to 5.9 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. The Agency found that 

the impact on employment nationally should be small on net, and 
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estimates that about 47,000 job-years of one-time construction 

labor could be supported or created by this rule, and a loss of 

14,000 to an increase of 33,000 jobs expected on an annual 

basis. For the proposal RIA, the Agency also examined the impact 

of the increases in electricity prices to industries outside of 

the electric power sector, and found that changes in product 

price and output should be less than 1 percent in 2015 for the 

many industries (100) included in the analysis. There may be 

impacts on a firm-level that could be higher than this, but 

these analysis results suggest that the economic impacts on 

average nationally should be modest. 

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 

have left the state as a result of substituting higher cost 

forms of electricity for coal. A commenter stated that coal-
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derived 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 lead to job losses and lost tax 

revenues, given the restrictive timeframe for compliance.

Response: The Agency’s estimate of increase in retail 

electricity price is an average of 3.0 percent in 2015, with a 

range of increases by region from 1.3 percent to 5.9 percent. 

Natural gas prices will only increase by 1.3 percent over the 

time horizon of 2015 to 2030. While electricity consumers will 

likely see a small price increase, it should be noted that these 

consumers will also experience the improvement in air quality 

from the reductions due to the rule, and the benefits of this 

improvement will exceed costs by at least six-fold. The price 

increases in electricity and natural gas should be considered in 

light of the substantial benefits offered 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

mentioned testimonials by power company CEOs stating that the 

proposed rule will not affect the economic health of the 
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industry and a survey showing nearly 60 percent of the coalfired units already comply with the EPA’s proposed mercury 

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 coalfired 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 

the rule strongly favor its adoption. These commenters stated 

that, contrary to the unfounded assertions by critics of EPA and 
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the rule, EPA has conducted a technically sound and conservative 

benefit-cost analysis showing that the proposed Rule’s 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 underestimate 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 

and that the proposed rule will stimulate job growth. A 

commenter quotes Dr. Josh Bivens of the Economic Policy 
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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 [Toxics Rule] 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 

jobs in the pollution abatement and control industry (which 

includes suppliers such as steelmakers).
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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 

offset rate increases, because low income customers will need to 

use less electricity due to economic necessity. The commenter
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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 in the retail 

electricity price range from 1.3 percent to 5.9 percent 

regionally in 2015, with an average increase nationwide of 3.0 

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 natural gas price as a 

result of this rule is expected to be 1.3 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. 

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 
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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 reliability 

as a result of this rule, and has determined that these impacts 

should not be significant and industry, along with relevant 

Federal Agencies, have the tools needed to address any 

reliability concerns. The Agency has prepared an updated 

technical support document (TSD) in support of the final rule, 

which is in the docket for this rulemaking. 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 several TSDs. 

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) decision makers and 

the public need to know the impacts specific to a particular 

rule in order to judge the merits of the regulation; 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 high-cost/low benefit regulation among other 
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rules that may have large net benefits. By analyzing each 

regulation separately, EPA makes clear statements about what 

impacts, costs, and benefits will be generated as a result of 

this particular regulation. 

The Agency does reflect on the cumulative impacts of our 

regulations, however. In March 2011, EPA issued the Second Clean 

Air Act Prospective Report which assessed at 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 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 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 exceed costs combined with extensive 

uncertainty analysis suggest it is very unlikely this result 

would be reversed using any reasonable alternative assumptions 
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or methods. This conclusion is likely to also be attributable to 

this rule as shown in the RIA.

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.

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 2 

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 5.9 percent in 

various parts of the country in 2015. 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 Appendix C of the RIA.

Comment: Commenters stated that communities near existing coalfired generation units will be especially hard-hit if the plants 
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are permanently retired. The communities will suffer from job 

loss and diminished tax revenue.

Response: While it is possible that there may be some negative 

local economic impacts associated with this rule, impacts such 

as retail electricity price increases should be modest (3.0 

percent on average in 2015, with a range of 1.3 percent to 5.9 

percent across the country). Also, the estimated number of early 

retirements according to the Agency that may result from this 

rule is 5.5 GW in 2015, or about 2 percent of all U.S. coalfired capacity in that year. These results are presented in the 

RIA for the final rule.

d. Retirements of coal-fired EGUs and shutdowns.

Comment: Multiple commenters discussed predictions for the 

number of coal-fired EGUs that are likely to retire as a result 

of the proposed rule and Transport rule. Commenters cited and 

provided references to 7 studies predicting retirements of 5 to 

65 GW in 2015, where 6 of the 7 predict retirements of 35 GW or 

more. A commenter estimated that the proposed rule, when viewed 

in conjunction with the entire body of new regulatory 

initiatives on the utility fleet, will impact roughly 400,000 MW 

of oil or coal-fired generation, or 40 percent of the current 

available capacity in the U.S. This commenter quotes the North 

American Electric Reliability Corporation (NERC) which predicts 
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the rules could jeopardize 30 to 70 GW of generating capacity by 

2015. A commenter predicts the early closure of many facilities 

as a result of the proposed rule and reports that these EGUs 

play a central role in a region’s economy since they are a 

source of jobs and contribute to the tax base. Other commenters

also quoted the NERC report and discussed the resulting problems 

from the predicted shut downs, which include adverse impacts of 

displacing coal-fired generation with other forms that do not 

provide the same kinds of grid support functionality, increased 

interconnection of variable energy sources such as solar and 

wind. The problem of grid operators being unable to know the 

locations and parameters of generator locations in enough time 

to facilitate transmission facilities is also mentioned, and the 

commenter requests a thorough reliability analysis given the 

compliance framework and timeline of the proposed rule.

Response: The Agency has conducted an updated reliability 

analysis for the final proposed rule, and the Agency will 

continue to work with other government agencies and relevant 

authorities regarding any potential reliability impacts of this 

rule to ensure they are adequately addressed without harming 

electricity supplies or foregoing the important public health 

benefits as part of this rule. The EPA estimates 5.5 GW of 

capacity will retire early as a result of this rule. We have not 
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prepared a cumulative impact analysis for the various power 

sector rules that have been finalized or are in process to be so 

because the Agency does not believe such an analysis would be as 

accurate and transparent as analyses for each of these 

individual rules. With regards to the studies that cited by the 

commenter, most do not hold up to scrutiny. The studies often 

make assumptions about the requirements of EPA’s rules that are 

inconsistent with and more stringent than EPA’s actual proposals 

and none accurately reflect this final rule. There are many 

layers of safeguards to avoid potential reliability concerns, 

and there are a host of tools that can be used to maintain 

reliability including new generation, demand response, energy 

efficiency, transmission upgrades, and energy storage. EPA will 

continue to work with industry and relevant authorities to 

ensure that reliability are adequately addressed.

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 
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unsustainable. The commenter quotes M.J. Bradley, who points 

out, “Of 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 

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 Toxics Rule are overstated and misleading. 

The commenter gives the example of the American Electric Power 

attempt to link its planned plant closures to the Toxics Rule, 

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. 
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Response: EPA thanks the commenter for these observations and 

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. 

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 
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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. 

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 

have been made as flexible as possible consistent with the CAA. 

The final rule allows some flexibility, like allowing averaging 

across units 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 
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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 

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 a loss of 17,000 jobs to an increase of 

35,000 jobs (all annual), but also recognizes important 

limitations to these estimates. The Agency’s estimate of impacts 

to short term construction jobs does account for the effects 
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from early retirements of power plants as a result of the rule, 

and this is shown in 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 mercury contamination. The commenter believes the HAP

accumulating in the waterways threatens the industry with 

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 

will improve waterways in Alabama and thus help the water-based 

recreation in that state. More information on the benefits of 

mercury and other HAP reductions can be found in Chapter 5 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.
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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.

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. EPA has provided supporting 

information as part of the preamble and RIA for this rule, along 
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with technical support documents 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 

(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 
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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 implementation of this rule will be 3 years after 

its promulgation, or the end of 2014. 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 3.0 

percent on average in 2015, with a range regionally from 1.3 

percent to 5.9 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 
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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, which is a 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 ICAC response that it will not for these 

reasons:

1. Power sector has demonstrated ability to install large 

number of systems in short time period.

2. Majority of coal plans have installed control systems 

already.

3. Fewer resource and labor-intensive control options being 

used for compliance.

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.
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Response: The EPA thanks the commenters for these observations. 

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 TSD on this subject 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 mercury with little support for other HAP reductions 

and failed to provide account of true costs and benefits.

Response: The benefits of this rule include the reductions in 

non-HAP emissions such as SO2 and PM2.5 that will take place based 

on EPA’s modeling. These reductions are credible and are 

considerable in size. The estimates of these benefits reflect 

extensive analysis that has been reviewed by EPA’s SAB, and 

reflects the latest scientific understanding on the subject. 

These benefits outweigh the total annual costs of the rule by at 

least six-fold. More information on the estimates and the 

methodology for their preparation can be found in the RIA for 

the rule. In addition, we are not able to monetize the benefits 
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from reductions of non-mercury HAP that will take place, but it

is clear that benefits will occur from reductions of these HAP.

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 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 include analyses by EIA, EEI, NERC, NERA, Credit 

Suisse, ICF, and Burns & McDonnell.

Response: The Agency recognizes that this rule has notable 

aggregate cost, and will affect most coal-fired EGUs in some 

way. However, the cost of the rule should be seen in the context 

of the regulated sector, which is anticipated to have annual 

revenues of roughly $350 billion by 2015. The Agency did not 
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complete a cumulative impact analysis for all of the power 

sector rules that have been finalized or are in process to be so 

because the Agency does not believe such an analysis would be as 

accurate and transparent as analyses for each of these 

individual rules. The techniques employed by the Agency in 

preparing our analyses are peer-reviewed for both costs and 

benefits, 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. The 

Agency has also revise 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. 

The Agency has not prepared an analysis of the impacts of the 

rule on State programs. The reductions in air pollution from the 

rule should be substantial and are well explained in the RIA and 
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in technical support documents found in the docket for this 

rulemaking. The 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: We thank the commenter for the comments. The MATS is a 

standard to reduce HAP, but it will also include revisions to 

the NOX, SO2, and PM emissions limits for utilities. Much of the 

HAP requirements will lead to co-benefits such as PM2.5 and SO2

reductions that could be of aid to States working on 

implementation of various NAAQS.

l. Miscellaneous.
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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

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 a number of the critical 

issues that 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.
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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 

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 non-mercury metals 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 

metals and filterable particulate standard. Because the test 

data that underlie the metals 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 using those same methods for determining compliance with 

the standard. 
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For stack test frequency, we modified the final rule to 

require quarterly testing if used to demonstrate continuous 

compliance, and included an exemption for testing in quarters 

with low utilization (less than 168 operating hours). 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 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 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 
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LEE status, you will revert to the requirements for Hg 

monitoring using CEMS or sorbent traps or, for oil-fired units, 

quarterly emissions testing.

Comment: Operating Parameter Limits: Some commenters objected 

strongly 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 simplify and 

streamline the final rule, we have retained your ability to 

define an operating limit and to monitor using a PM CPMS as an 

option to periodic emissions testing. 

The final rule establishes the PM CPMS as an operating 

limit monitor and not a direct filterable PM emission monitoring 
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requirement that meets PS 11 requirements. Although we recognize 

the importance of continued control device performance to ensure 

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.

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 Part 75 

monitoring requirements. Some commenters questioned the ability 

of the technology to demonstrate compliance with 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 

the CAMR-based requirements for Hg monitoring in place of the 

general 40 CFR Part 63 standards. 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 
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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 

certain advantages. For existing and some of the new unit 

standards, the level of the NIST-traceable Hg standard will be 

adequate and consistent with existing applications of Hg 

CEMS. For the lowest limits and other applications where the 

system offers advantages, affected facilities may opt to use 

sorbent trap monitoring systems to comply. As noted in a 

previous response above, there are data in the recent draft 

report entitled “Determining the Variability Of CMMS At Low Hg 

Levels,”

322 that demonstrate reasonable performance of at least 

one Hg CEMS at Hg levels below 1.0 microgram per cubic meter 

 

322 http://www.icci.org/reports/10Laudal6A-1.pdf
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(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 as a 

surrogate for HCl, there were some concerns with aspects of the 

proposal. First, commenters requested that the requirements rely 

on Part 75 given that their sources were already meeting those 

requirements and not establish new requirements, especially a 

fourth linearity level and the application of 7-day calibration 

error tests for units with low concentrations (where 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 a requirement for a linearity check even for SO2

monitors with low span values (≤ 30 ppm). You can already report 

linearity tests for these units within the context of the 
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existing ECMPS reporting without triggering any critical errors. 

This test can be accommodated within the current framework 

without causing issues for Part 75 reporting. The 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. That concern was 

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 limits set in the final standard. 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 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 
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monitoring including: 

1) Using HCl CEMS and/or HF CEMS for compliance including 

CEMS complying with PS 15,

2) Seeking approval for an alternative HCl monitoring 

procedure through 40 CFR 63.7(f),

3) Monitoring SO2 continuously as a surrogate for acid gas 

HAP at facilities equipped with FGD technology for SO2, and

4) Frequent reference method testing.

Including these options in the final rule provides 

flexibility to adopt CEMS monitoring options as the technology 

continues to mature and the EPA performance specifications 

become 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 on a bypass stack. That 

approach works within the broad context of an emissions trading 

program, but does not work when evaluating compliance with a 

specific emission limit over a shorter period. Thus, we have 

provided two other options. One is to monitor the bypass stack, 

consistent with the proposed rule. The other is to treat any 
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hours of bypass stack emissions as periods of monitor downtime. 

In general, this is consistent with our approach to startup, 

shutdown, and malfunction periods in that we treat those periods 

as subject to a work practice standard. That generally obviates 

the need to monitor the bypass stack as the emission limit does 

not apply during such periods when your source is likely to 

operate a bypass stack.

Comment: Part 75 Issues. There were a number of general comments 

about the value of generally relying on Part 75 requirements, 

including elements such as conditional data validation. The 

commenters generally agreed that the Part 75 bias test and bias 

adjustment factor, and the 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 Part 75 where appropriate. 

One of those examples is the inclusion of conditional data 

validation for Hg CEMS. One area of departure is 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 
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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 emissions 

rate limit (e.g., lb/MMBtu or lb/MWh). We agree that data 

quality certainty associated with any calculated value decreases 

with the collection of fewer data such as would occur with 

extended periods of monitoring system downtime. Even so, we 

believe also that it is necessary and critical to compliance

with the regulation that a source uses all measured data 

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 x 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 and 

that are not covered by exceptions allowed in the final rule. 

On the issue of applying a data substitution procedure to 
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represent actual emissions or pollution control performance, we 

believe that defensibility concerns make it incumbent on you 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 

authority be concerned about the representativeness of data such 

as during periods of missing data, either 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 that 

failure to collect required or otherwise excepted data is a 

deviation from the rule will provide the necessary incentive to 

collect data sufficient to demonstrate compliance with the 

limits in the final rule.
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Comment: Recordkeeping. Several commenters opposed the 

requirements related to maintaining records on site and for 5

years.

Response: We believe the record keeping 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 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 
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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. 

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 continuously measured pollutants and 

we will make these minor modifications for receipt of the 

additional data demands. We also recognize the need for 

substantial modifications to the ECMPS to accommodate the data 

needs for periodically measured pollutants. Although major 
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modifications of the ECMPS would be required for periodic 

compliance tests by isokinetic and instrumental test methods, 

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 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 our 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 
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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 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 
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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.

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 

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. This level of control is commonly referred to as 

best demonstrated technology (BDT). 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), 
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industrial-commercial institutional steam generating units (40 

CFR Part 60, subpart Db), and small industrial-commercialinstitutional steam generating units (40 CFR Part 60, subpart 

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 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 BDT for these 

sources. The NSPS for small industrial-commercial-institutional 
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steam generating units (40 CFR Part 60, subpart Dc) were 

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 this Final NSPS

The final rule amends the emission standards for SO2, NOX, 

and PM for 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 

similar testing, monitoring, and other compliance provisions 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 
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the type of fuel burned. The PM emissions standard for modified 

EGUs is unchanged from the existing requirements of 6.4 ng/J 

(0.015 lb/MMBtu) heat input or 99.8 percent reduction regardless 

of the type of fuel burned. Compliance with this emission limit 

can be determined using similar testing, monitoring, and other 

compliance provisions 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 SO2

emission limit for new and reconstructed EGUs that burn over 75 

percent coal refuse (by heat input) on an annual basis is 180 

ng/J (1.4 lb/MWh) gross energy output or 94 percent reduction. 

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

with one exception. The SOs emission limit for modified EGUs that 

burn over 75 percent coal refuse (by heat input) on an annual 

basis is 190 ng/J (1.5 lb/MWh) gross energy output or 90 percent 

reduction. Compliance with the SO2 emission limit is determined 

on a 30-day rolling average basis using a CEMS to measure SO2
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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 NOX emission limit for new 

and reconstructed EGUs that burn over 75 percent coal refuse (by 

heat input) is 110 ng/J (0.85 lb/MWh) gross energy output. The 

NOX limit for modified 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-day 

rolling average basis using similar testing, monitoring, and 

other compliance provisions in the proposed rule.

As an alternate to the NOX standard, owners/operators of new 

and reconstructed EGUs may elect to comply with a combined NOX/CO 

standard of 140 ng/J (1.1 lb/MWh) with one exception. The NOX/CO 

emission limit for new and reconstructed EGUs that burn over 75 

percent coal refuse (by heat input) on an annual basis is 160 

ng/J (1.3 lb/MWh) gross energy output. Finally, owners/operators 

of modified EGUs may elect to comply with a combined NOX/CO 

standard of 190 ng/J (1.5 lb/MWh).

B. Additional Amendments

See the Response to Comments document.

X. Summary of Significant Changes Since Proposal
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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 

PM. 

The proposal included requested comment on if the final 

standard should include a standalone NOX standard or a combined 

NOX/CO standard. The final standard includes a standalone NOX

standard and an optional, but not required, combined NOX/CO 

standard as an alternative to the amended NOX standard. 

Similarly, the proposal included a request for comment on if the 

standard should be based on gross or net output. The final 

standards are based on an amended definition of gross output 

with an optional net output based standard.

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 multipollutant control technologies, but not advanced combustion 

controls.

B. Requirements during Startup, Shutdown, and Malfunction
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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, which require 

following manufacturers specifications for minimizing periods of 

startup and shutdown, in lieu of numeric emission limits. For 

malfunctions, the EPA is finalizing affirmative defense language 

to this final rule for exceedances of the numerical emission 

limits that are caused by malfunctions.

XI. Public Comments and Responses to the Proposed NSPS

See the Response to Comments document.

XII. Impacts of These Final Rules

A. What are the air impacts?

The EPA anticipates significant emission reductions under 

the final rule from coal-fired EGUs, which are of particular 

interested 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 68 percent, and PM2.5 emissions 

reduced by 20 percent from coal-fired EGUs greater than 25 MW. 

In addition, the EPA projects SO2 emission reductions of 41 

percent, and annual CO2 reductions of 1 percent from coal-fired 

generation greater than 25 MW by 2015, relative to the base 

case. See Table 7.

TABLE 7. SUMMARY OF EMISSIONS REDUCTIONS FROM COAL-FIRED EGUS 

GREATER THAN 25 MW (TPY)
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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 8 6 215 1,881

Change -1.4 0.0 -18 -40 -54 -25

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 gasses. 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 emissions 

reductions.

B. What are the energy impacts?

Under the provisions of this proposed rule, the EPA

projects that approximately 5.5 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 uneconomic to 

maintain and removed from operation by 2015. These units are 

predominantly smaller and less frequently used generating units 

dispersed throughout the country. If current forecasts of either 
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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.

There are other important energy market implications of the 

final rule. Average nationwide retail electricity prices are 

projected to increase in the continental U.S. by 3 percent in 

2015. The average delivered coal price increases by less than 2 

percent in 2015 as a result of shifts within and across coal 

types. The EPA also projects that electric power sectordelivered natural gas prices will increase by about 0.7 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 11 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.

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 
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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 what the power industry will directly expend to comply with 

the EPA’s requirements.

The EPA projects that the annual incremental compliance 

cost of MATS is $9.2 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.

D. What are the economic impacts?

For this final rule, EPA analyzed the costs using IPM. IPM 

is a dynamic linear programming model that can be used 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.

1. EPA performed a screening analysis for impacts on small 
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entities by comparing compliance costs to sales/revenues (e.g., 

sales and revenue tests). EPA’s analysis can be found in Chapter 

7 of the RIA for this rule. EPA has also prepared a Final 

Regulatory Flexibility Analysis (FRFA) that discusses that 

discusses alternative regulatory or policy options that minimize 

the rule’s small entity impacts. 

2. 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. Such an analysis is of particular concern in the 

current economic climate as sustained periods of excess 

unemployment may introduce a wedge between observed (market) 

wages and the social cost of labor. In such conditions, 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). EPA 

also includes estimates of job impacts associated with the final 

rule, where possible. EPA presents an estimate of short-term 

employment opportunities as a result of increased demand for 

pollution control equipment. Overall, the results suggest that 
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the final rule could support a net of roughly 47,000 job years323

in direct employment impacts in 2015.

3. The basic approach to estimate these employment impacts 

involved using projections from IPM from the final rule 

analysis, in particular the amount of existing coal-fired 

capacity that is projected to be retrofit with pollution control 

technologies. This data, along with data on labor and resource 

needs of new pollution controls and labor productivity from 

engineering studies and secondary sources, is used to estimate 

employment impacts for the pollution control industry in 2015. 

For more information, please refer to the Chapter 6 and appendix 

6B the RIA for this analysis.

4. The EPA relied to Morgenstern, et al. (2002), identify three 

economic mechanisms by which pollution abatement activities can 

indirectly influence jobs:

 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 

 

323 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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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 spending on pollution 

abatement results in an small net increase of 1.6 jobs; the 

estimated effect is not statistically significant different from 

zero. As a result, the authors conclude that increases in 

pollution abatement expenditures do not necessarily cause 

economically significant employment changes. The conclusion is 

similar to Berman and Bui (2001) who found that increased air 

quality regulation in Los Angeles did not cause large employment 

changes.324 For more information, please refer to the RIA for 

this final rule.

The ranges of job effects 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) 

 

324 For alternative views in economic journals, see Henderson 

(1996) and Greenstone (2002).
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Demand 

Effect

Cost 

Effect

Factor Shift 

Effect

Net 

Effect

Change in 

Full-Time Jobs 

per Million 

Dollars of 

Environmental 

Expenditurea

−3.56 2.42 2.68 1.55

Standard Error 2.03 0.83 1.35 2.24

EPA estimate 

for Final 

Ruleb

-38,000 to 

+2,100 

+4,000 to 

+20,000

+200 to 

+27,000

-14,000 to 

+30,000

a Expressed in 1987 dollars. See footnote a from Table 6-3 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 which are 

not considered in the Morgenstern, et al., study. Although EPA 

has considered some economy-wide changes in industry output as 

shown earlier with the Multi-Market model, we do not have 

sufficient information to quantify other associated 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. 

In 2000, the NAS Study was issued which provides a thorough 

review of the effects of MeHg on human health (NRC, 2000). Many 

of the peer-reviewed articles cited in this section are 
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publications originally cited in the MeHg Study. In addition, 

the EPA has conducted literature searches to obtain other 

related and more recent publications to complement the material 

summarized by the NRC in 2000.

b. Neurologic Effects of Exposure to MeHg. In its review of the 

literature, the NAS found neurodevelopmental effects to be the 

most sensitive and best documented endpoints and appropriate for 

establishing an RfD (NRC, 2000); in particular NAS supported the 

use of results from neurobehavioral or neuropsychological tests. 

The NAS report (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 

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 NRC (2000) concluded that 
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“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 NRC also stated that 

“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 to 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 concluded that evidence that human exposure to MeHg 

caused genetic damage is inconclusive; they note that some 
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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 

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 Faroes and Seychelles 

populations.

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 
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studies have shown an association between Hg exposure and 

specific types of cancer incidence (e.g., acute leukemia and 

liver cancer) (NAS, 2000).

There is also some evidence of reproductive and renal 

toxicity in humans from MeHg exposure. However, overall, human 

data regarding reproductive, renal, and hematological toxicity 

from MeHg are very limited and are based on either studies of 

the two high-dose 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 fish325

reports results for numerous species including trout, bass 

(large and smallmouth), northern pike, carp, walleye, salmon, 

 

325 Crump, KL, and Trudeau, VL. Mercury-induced reproductive 

impairment in fish. Environmental Toxicology and Chemistry. Vol. 

28, No. 5, 2009.
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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 

deficits would have an effect on populations.

Mercury also affects avian species. In previous reports326

much of the focus has been on large piscivorous species in 

particular the common loon. Significant adverse effects on 

breeding loons from Hg have been found to occur including 

behavioral (reduced nest-sitting), physiological (flight feather 

asymmetry) and reproductive (chicks fledged/territorial pair) 

effects and reduced survival.327 Additionally, Evers, et al. (see

footnote 5), report that they believe that the weight of 

 

326 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. Office of Air Quality Planning and Standards, Research 

Triangle Park, NC., March; EPA report no. EPA-452/R-05-003. 

Available on the Internet at 

<http://www.epa.gov/ttn/ecas/regdata/RIAs/mercury_ria_final.pdf

327 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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evidence indicates that population-level 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 and frogs. The white ibis has been observed to have 

decreased foraging efficiency328 and have been shown to exhibit 

decreased reproductive success and altered pair behavior.329 In 

egrets, Hg has been implicated in the decline of the species in 

south Florida330 and Hoffman

331 has shown that egrets show 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 

 

328 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.

329 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.

330 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.

331 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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to a large portion of the U.S.

Insectivorous birds have also been shown to suffer adverse 

effects due to Hg exposure. These songbirds such as Bicknell’s 

thrush, tree swallows, and the great tit have shown reduced 

reproduction, survival, and changes in singing behavior. Exposed 

tree swallows produced fewer fledglings,332 lower survival,333 and 

had compromised immune competence.334 The great tit has exhibited 

reduced singing behavior and smaller song repertoire in areas of 

high contamination.335

In mammals adverse effects have been observed in mink and 

river otter, both fish eating species. For otter from Maine and 

Vermont, maximum concentrations on Hg in fur nearly equal or 

exceed a concentration associated with mortality and 

concentration in liver for mink in Massachusetts/Connecticut and 

the levels in fur from mink in Maine exceed concentrations 

 

332 Brasso, RL, and Cristol, DA. Effects of mercury exposure in 

the reproductive success of tree swallows (Tachycineta bicolor). 

Ecotoxicology. 17:133-141, 2008.

333 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.

334 Hawley, DM, Hallinger, KK, Cristol, DA. Compromised immune 

competence in free-living tree swallows exposed to mercury. 

Ecotoxicology. 18:499-503, 2009.

335 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.
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associated with acute mortality.336 Adverse sublethal effects may 

be associated with lower Hg concentrations and consequently be 

more widespread than potential acute effects. These effects may 

include increased activity, poorer maze performance, abnormal 

startle reflex, and impaired escape and avoidance behavior.337

h. Methodology for Hg Benefits Estimation. The EPA has conducted 

a national-scale analysis the benefits to recreational anglers 

of avoided IQ loss that reductions of Hg emissions and 

subsequent deposition required by this rule will achieve. 

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 

 

336 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.

337 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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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 

freshwater fishing trips (and exposed individuals) from each 

census tract matched to each waterbody type, the EPA used statelevel 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 FHWAR data.

Data from NSRE 1994 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 
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Page 614 of 984

mothers’ ingestion of Hg 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 IQ decrement in 

offspring resulting from in-utero exposure to Hg through 

mothers’ fish consumption, the following dose-response 

relationship 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 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 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. 
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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 

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). With a 7 percent discount rate assumption, 

the value IQ estimates range from $893 to $1,958.

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 value of these losses ranges 
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Page 616 of 984

from $204.8 million to $292.5 million.338 These 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 value range is considerably lower: $22.8 million to 

$50.0 million.

For the five emission reduction scenarios, 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 Toxics Rule 

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.

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, ozone, NOX, 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

 

338 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 

proportional in equilibrium, but the MMaps approach does not 

provide any information on the time lag of response.
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and direct PM2.5 and climate benefits resulting from CO2

reductions. Additional co-benefits are expected to result from 

decreases in PM2.5 morbidity impacts, decreases in nitrogen and 

sulfur deposition, and improvements in visibility in national 

parks and wilderness areas. Total co-benefits are thus expected 

to be higher than the partial estimates of co-benefits provided 

here. We estimate the monetized health and climate co-benefits 

of this rule in 2016 at a 3 percent discount rate are $37 

billion to $91 billion or $33 billion to $82 billion at a 7 

percent discount rate (2007$), given uncertainty about the 

relationship between PM2.5 concentration and health effects. Using 

alternate relationships between PM2.5 and premature mortality 

supplied by experts, higher and lower health co-benefits 

estimates are plausible, but most of the expert-based estimates 

fall between these two estimates.339

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 

 

339 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.
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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),340 but here the 

air quality modeling used a better spatial representation of the 

emission changes from EGUs. 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 incidences 

of PM2.5-related health effects in 2016 resulting from this rule. 

Table 10 presents the estimated annual monetary value of 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 monetized health cobenefits.

TABLE 9. ESTIMATED REDUCTIONS IN INCIDENCES OF PM2.5-RELATED 

HEALTH EFFECTS IN 2016a

Health Effect Number of Reduced Cases

Adult Premature Mortality

Pope et al. (2002) (age >30) 4,300

(1,200 to 7,300)

 

340 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 

Atmos Health (2009) 2:169–176.
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Laden et al. (2006) (age >25)

11,000

(5,000 to 17,000)

Infant Premature Mortality 

(< 1 year)

20

(-22 to 62)

Chronic Bronchitis 2,900

(88 to 5,600)

Non-fatal heart attacks 

(age > 18)

4,800

(710 to 5,000)

Hospital admissions—respiratory 

(all ages)

840

(330 to 1,300)

Hospital admissions—cardiovascular 

(age > 18)

1,800

(1,300 to 2,200)

Emergency room visits for asthma 

(age < 18)

3,200

(1,600 to 4,700)

Acute bronchitis 

(age 8-12)

6,300

(-1,400 to 14,000)

Lower respiratory symptoms 

(age 7-14)

81,000

(31,000 to 130,000)

Upper respiratory symptoms 

(asthmatics age 9-11)

61,000

(11,000 to 110,000)

Asthma exacerbation 

(asthmatics 6-18)

130,000

(4,500 to 450,000)

Lost work days 

(ages 18-65)

550,000

(460,000 to 630,000)

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
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Health Effect Monetized Benefits

Adult Premature Mortality

Pope, et al. (2002) (age >30)

3% discount rate $34

($2.7 to $100)

7% discount rate $31

($2.4 to $93)

Laden, et al. (2006) (age >25)

3% discount rate $88

($7.6 to $250)

7% discount rate $79

($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 $0.2)

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 $37

($2.8 - $110)

7% discount rate $33

($2.5 - $100)
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Laden, et al. (2006)

3% discount rate $90

($7.7 - $260)

7% discount rate $81

($7.0 - $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.

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. For this rule we cite two key empirical 

studies, one based on the American Cancer Society cohort study341

and the other based on the extended Six Cities cohort study.342

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.

 

341 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.

342 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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These models assume that all fine particles, regardless of 

their chemical composition, are equally potent in causing 

premature mortality because the scientific evidence is not yet 

sufficient to allow differentiation of effects estimates by 

particle type. Even though we assume that all fine particles 

have equivalent health effects, the benefit-per-ton estimates 

vary between precursors because each ton of precursor reduced 

has a different propensity to form PM2.5.

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 

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 literatures (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 provides a reasonable indication 

of the expected health co-benefits of the rulemaking in future 

years under a set of reasonable assumptions.
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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 levels above 

and below a “bright line” threshold, the EPA includes a “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 

PM2.5-related premature mortality diminishes as baseline 

concentrations of PM2.5 are lowered.
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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) 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.

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 models 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.

It should be emphasized that the monetized co-benefits 

estimates provided above do not include benefits from several 

important benefit categories, including exposure to other air 

pollutants, ecosystem effects, and visibility impairment. 
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Page 625 of 984

b. Non-Climate Welfare Co-Benefits. Emission controls installed 

to meet 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$). Since the distribution of emission reductions did 

not change substantially in the visibility regions studied, 

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; the role of 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 four categories of public welfare and environmental 

impacts related to reductions in emissions required by this rule 
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Page 626 of 984

in the RIA.

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 damages 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 

executive branch entities, and 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; 5/7/10). The SCC Technical 

Support Document (SCC TSD) provides a complete discussion of the 

methods used to develop these SCC estimates.343

 

343 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 
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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 

fourth value is the 95th percentile of the SCC from all three 

models at a 3 percent discount rate. It is included to represent 

higher-than-expected impacts from temperature change further out 

in the tails 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 models as well as the use of a probability density 

function for equilibrium climate sensitivity. Treating climate 

 

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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sensitivity probabilistically results in more high temperature 

outcomes, which in turn lead 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 $350 million (2007$), 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 $37

($2.8 - $110)

7% discount rate $33

($2.5 - $100)

Laden, et al. (2006)

3% discount rate $90

($7.7 - $260)

7% discount rate $81

($7.0 - $240)

Climate-related Co-Benefits (3% 

discount rate) $0.35

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 $91

($8.1 - $260)
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7% discount rate $82

($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.

We estimate the monetized total co-benefits of this rule in 

2016 at a 3 percent discount rate are $37 billion to $91 billion 

or $33 billion to $82 billion (2007$) at a 7 percent discount 

rate, given uncertainty about the relationship between PM2.5

concentration and health effects. These estimates account for 

the quantified health and climate benefits described above.

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 

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 EO 12866 and any changes in 

response to OMB recommendations have been documented in the 

docket for this action. For more information on the costs and 
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benefits for this rule, please refer to Table 10 of this 

preamble.

When estimating the human health benefits and compliance 

costs in Table 10 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;

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 
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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 endeavor 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 

benefits for the final rule at discount rates of 3 percent and 7 

percent is in Table 10 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 
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Reduction Act, 44 U.S.C. 3501 et seq. 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 

Provisions. The recordkeeping requirements require only the 

specific information needed to determine compliance.

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 $128.6 

million. This includes 548,764 labor hours per year at a total 

labor cost of $36.3 million per year, and total non-labor 

capital costs of $92.3 million per year. This estimate includes 

initial and annual performance tests, semiannual excess emission 
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reports, developing a monitoring plan, notifications, and 

record-keeping. Initial capital expenses to purchase monitoring 

equipment for affected units are estimated at a cost of $143.1 

million. This includes 342,967 labor hours at a total labor cost 

of $22.7 million for planning, selection, purchase, 

installation, configuration, and certification of the new 

systems and total non-labor capital costs of $120.4 million. 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 
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subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the 

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 
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recommendations is found in the Panel Report (EPA-HQ-OAR-2009-

0234-2921). A summary of the Panel’s recommendations is 

presented at 76 FR 24975.

As required by RFA section 604, we also prepared a final 

regulatory flexibility analysis (FRFA) for today’s 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 Considered

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 (Section 

112(n) Revision Rule) 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 mercury from EGUs pursuant to CAA 

section 111 (CAMR), May 18, 2005, 70 FR 28606). The Section 

112(n) Revision Rule 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 rule in response to 
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the court’s decisions. Under authority of CAA section 112, the 

EPA is proposing NESHAP for EGUs that will regulate units at 

both major and area sources, henceforth referred to as the MATS.

2. Statement of Objectives and Legal Basis for Final Rules

The MATS would protect air quality and promote public 

health by reducing emissions of the 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 Section 112(n) Revision 

Rule reverted the status to that of 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.

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 
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below. These comments can also be found in their entirety in the 

response to comment document in the docket.

Comment: 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, since they will be able 

to make more money serving larger utilities.

Response: The preamble to the proposed rule (76FR 25054, May 3, 

2011) provides a detailed discussion of how the EPA determined 

compliance times for the proposed rule. The EPA has provided 

pursuant to CAA section 112(i)(3)(A) the maximum 3hree-year 

period for sources to come into compliance. Sources may also 

seek a 1-year extension of the compliance period from their 

Title V permitting authority if the needs that time to install 

controls. See CAA section 112(i)(3)(B). If the situation 

described by commenters (i.e., where smaller utilities and those 

in rural areas are less able to get vendor responses to requests 

for proposals than larger utilities) results in the source 

needing additional time to install controls, they would be in a 

position to request the 1-year extension. The EPA discusses in 

more detail elsewhere in this notice how the Agency plans to 

address those units that are still unable to comply within the 

statutorily mandated period.
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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 

simplifications of compliance and reporting requirements, and 

subsequently 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. Two commenters stated that the EPA did not 

identify regulatory alternatives for the SBAR Panel to consider. 

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 
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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 

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 SER panel 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 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, record keeping 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.
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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 

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.

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, 
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the proposed rule. The EPA has endeavored to make the final 

regulations flexible and cost efficient while adhering to the 

requirements of the CAA.

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.

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 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 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 
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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. The EPA discusses in more detail elsewhere in 

this notice how the agency plans to address those units that are 

still unable to comply within the statutorily mandated period.

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 powers is critical to communities, 

jobs, economic viability and electric reliability. One commenter 

that is a generating and transmissions electric cooperative 

which qualifies as a small entity and believes the proposed rule 

will ultimately result in increased electricity costs to its 

members and will negatively impact the economies of the 
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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 proposed 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 

relative to the projected revenue from generation. Thus, the 
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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. Another commenter believes 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. The commenter points out that 

relaxation in standards would not only harm downwind governments 

and small businesses who incur higher labor costs due to 

pollution, but will harm other small businesses and state, 

tribal and local governments developing or operating generation 

facilities using modern and less polluting generation 

technologies. The EPA acknowledges the commenter’s assertion.

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 
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control requirements. The commenter notes that the capital 

costs for emissions control at small-sized 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 upon which to 

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 its proposal of reduced 

monitoring requirements for existing units that qualify as low 

emitting EGUs. 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 
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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 

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. The 

continuous compliance alternatives would be available to all 

affected sources, including small entities. As monitoring 

alternatives to use of PM CEMS and HCl CEMS, sources would be 

allowed to conduct additional performance testing. Sorbent trap 

monitoring would be 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 given itself 

the opportunity to engage in meaningful outreach and 

consultation with small entities and therefore recommends that 
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the EPA seek to revise the court-agreed deadlines to which this 

rulemaking is subject, re-convene 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 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 
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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 for excluding 

serious consideration of a separate standard for area sources. 

The commenter suggests that the EPA reconvene the SBAR Panel to 

solicit more meaningful consultation with the SERs; the EPA 

prepare an IRFA that includes descriptions of specific 

regulatory alternatives, the effects on small entities of the 

regulatory alternatives, and the policy reasons for selected 

among them; and the EPA release the IRFA for additional public 

comment before making any decisions about the EPA’s preferred 

options for final rulemaking. The commenter recognizes that the 

EPA will have to request of the litigants and the court an 

extension of the timeline for final rulemaking but believes

strongly that this action is necessary. 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 
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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 provide any opportunity for smaller emitters to use 

GACT — often used in other EPA MACT regulations to alleviate the 

regulatory costs and operational difficulties that would have 

burdened other small businesses including dry cleaners, metal 

fabricating, metal finishing, and others. A commenter believes 

it is likely that different numerical or work practice standards 

are appropriate for area sources of HAP, just as in other 

rulemakings such as the RICE rule, and that the EPA would have 

provided the opportunity for small entities to make such 

demonstration had they followed their own regulatory 

requirements.

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. 

Several commenters are concerned that recommendations made 

by the SERs were ignored and not considered or discussed in the

proposed rulemaking. Specifically, commenters cite SER 

recommendations regarding subcategorization and separate 

standards for area sources. The EPA disagrees with the 

commenters. The preamble to the proposed standards includes 

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 
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subcategorizing on those bases. The preamble to the proposed 

standards also includes a 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).

One commenter suggests that the EPA 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 non-discretionary 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. If plaintiffs in 

the American Nurses litigation objected to an extension request, 

which we believe they would have based on their comments on the 

proposed rule, 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 for extension that it was impossible 

to finalize the rule by the deadline provided in the Consent 
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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 

4 billion kilowatt hours (kWh) of production or less;
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(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 

affect combustion units with an equivalent electricity 
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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 83 potentially affected small entities 

that are affiliated with 105 electric generating units.

5. Compliance Cost Impacts

The number of potentially affected small entities by 

ownership type and potential impacts of MATS are presented in 
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Chapter 7 of the RIA and summarized here. The EPA estimated the 

annualized net compliance cost to small entities to be 

approximately $79 million in 2015 (2007$).

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 83 small entities identified, The 

EPA’s analysis shows 49 entities may experience compliance costs 

greater than 1 percent of base generation revenues in 2015, and 

36 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 36 of the 83 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 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 country. 

Entities operating in regulated or cost-of-service markets 
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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 $169 

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 

and operating costs increase across all ownership types, but the 
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direction of changes in electricity revenues vary 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 

a generating capacity of less than 25 MW, small entities that do 
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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 are 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. The 

EPA has chosen to finalize work practice standards because the 
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significant majority of data for measured organic HAP emissions 

from EGUs are below the detection levels of the EPA test 

methods, and, as such, the Agency considers it impracticable to 

reliably measure emissions from these units. Descriptions of the 

work practice requirements for startup and shutdown, as well as 

organic HAP, 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 

practicable to adopt the proposed subcategories, the EPA 

maintained the existing subcategories and spilt the “liquid oil-
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fired units” subcategory into two individual subcategories –

continental and non-continental units.

d. MACT floor calculations. As recommended by the EPA SBAR Panel 

representative, the EPA established the MACT floors using all 

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. Additionally, following proposal, the EPA reviewed 

and revised the procedure intended to account for the 

contribution of measurement imprecision to data variability in 

establishing effective emissions limits.

e. Alternatives not adopted. The EPA chose not to 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 desire to promote, 

and give credit for, 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 
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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 reduction standards for HAP, 

as explained further in the response to comments.

The EPA chose 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 chose 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 
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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.

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 Unfunded Mandates Reform Act of 1995 

(UMRA), 2 U.S.C. 1531-1538, requires Federal agencies, unless 

otherwise prohibited by law, to assess the effects of their 

regulatory actions on state, local, and tribal governments and 

the private sector. 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 one year. Accordingly, EPA has prepared under UMRA 

section 202 a written statement which is summarized below.
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Before promulgating an EPA rule for which a written 

statement is needed under UMRA section 202, UMRA section 205, 2 

U.S.C. 1535, generally requires the EPA 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. Moreover, 

UMRA section 205 allows the EPA to adopt an alternative other 

than the least costly, most cost-effective or least burdensome 

alternative if the Administrator publishes an explanation why 

that alternative was not adopted.

In a manner consistent with the intergovernmental 

consultation provisions of UMRA section 204, the EPA carried out 

consultations with the governmental entities affected by this 

rule. The EPA held meetings with states and Tribal 

representatives in which the Agency presented its plan to 

develop a proposal and provided opportunities for participants 

to provide input as part of the rulemaking process. The EPA has 

also analyzed the economic impacts of the final MATS rule on 

government entities and this section presents the results of 

that analysis. This analysis does not examine potential indirect 

economic impacts associated with the final rule, such as 

employment effects in industries providing fuel and pollution 
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control equipment, or the potential effects of electricity price 

increases on industries and households.

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 

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 ${xx} in annual direct compliance costs on 

an estimated {xx} state or local governments. Specifically, we 

estimate that there are {xx} municipalities, {xx} states, and 

{xx} political subdivisions (i.e., a public district with 
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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 

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 from state/local governments. 

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 
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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 

implications, because it may impose substantial direct 

compliance costs on tribal governments, and the Federal 

government will not provide the funds necessary to pay those 

costs. Accordingly, EPA provides the following tribal summary 

impact statement as required by section 5(b).

The EPA offered consultation with Tribal officials early in 

the process of developing this regulation to permit them to have 

meaningful and timely input into its development. Consultation 

letters were sent to 584 Tribal leaders. The letters provided 

information regarding the EPA’s development of NESHAP for EGUs 

and offered consultation. Three consultation meetings were held 

on 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, Fond du 

Lac Band of Chippewa; January 5, 2011, with the Forest County 
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Potawatomi, and a representative from the National Tribal Air 

Association. 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 on the reservations. Particularly, 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 concerns expressed by tribes 

were about how the Agency would consider variability in setting 

the standards, 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 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 National 

Tribal Air Association, and a webinar for tribes on the proposed 
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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, and the impacts 

on employment of tribal members at both the NGS and the mine. 

More specific comments can be found in the docket.

As required by section 7(a), EPA’s Tribal Consultation 

Official has certified that the requirements of the EO have been 

met in a meaningful and timely manner. A copy of the 

certification is included in the docket for this action.

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 
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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 may be especially 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 

different ways in the analyses associated with this rulemaking, 

and are summarized in the RIA.

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 
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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 percent price increase for electricity 

nationwide in 2016 and a less than 2 percent percentage fall in 

coal-fired power production. The EPA projects that delivered 

natural gas prices will increase by about 0.7 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 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.
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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 

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 Society of 

Mechanical Engineers (ASME) PTC 19-10-1981-Part 10, “Flue and 

Exhaust Gas Analyses,” is cited in the final rule for its manual 

method for measuring the O2, CO2, and CO content of exhaust gas. 

This part of ASME PTC 19-10-1981-Part 10 is an acceptable 

alternative to Method 3B.

The voluntary consensus standard ASTM D6348-03(2010),

“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, 
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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 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 D6784-20, “Standard 

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 mercury continuous 

monitoring systems under this final rule. Because of the 

limitations of this method in terms of total sampling volume, it 
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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 surrogates subject to emission 

standards in the final rule were impractical alternatives to EPA 

test methods for the purposes of this final 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.

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 since 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 
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frequency and validity range for calibration of the temperature 

sensors.

The voluntary consensus standard ASTM D3464-96 (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 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 
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Nitrogen in Enclosed Combustion Flue Gas Streams,” is 

unacceptable as a substitute for EPA Method 3A since 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 

drift checks after each run.

Two very similar voluntary consensus standards, ASTM D5835-

95 (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) 
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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 

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 
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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 

requirements, and instead presents the options available and the 

pro’s and con’s 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 
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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 

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. 
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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 

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
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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 

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 

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.
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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 

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 proposed 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.
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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 proposed 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. 

The EPA has determined that this final rule will not have 

disproportionately high and adverse human health or 

environmental effects on minority, low income, or indigenous 
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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, or 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 

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 
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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 and has the 

potential to affect the cost structure of the utility industry 

and could lead to shifts in how and where electricity is

generated.

Today’s final rule is one of a group of regulatory actions 

that the EPA 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 

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 
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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 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 

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 
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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 was 

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. 

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 
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HAP are presented in the preamble and in the RIA for this rule.

2. Potential Environmental and Public Health Impacts to 

Vulnerable 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 

(so-called “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 

source. In addition, several of the pollutants emitted by these 

sources, such as Hg and SO2, are known to travel long distances 

and harm both the environment and human health hundreds or even 
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thousands of miles from where they were emitted. 

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 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 

elevated levels of Hg deposition around most U.S. EGUs. 

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 was extracted 

from the 2000 census data which was provided to the EPA by the 

US 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-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 
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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 

because of various stack heights there is the potential for 

dispersion beyond 3 miles. To the extent that any minority, low

income, or 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 
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emissions reductions called for by this rule. The results of the 

EPA’s demographic analysis for coal fired EGUs 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)

White

Africa

n 

Americ

an 

Native 

Americ

an 

Other 

and 

Multir

acial 

Hispan

ic

Minori

ty

Below 

Povert

y Line

Near

Source

Total 

(3 mi)

8.78 2.51 96.9 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 

where 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.
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b. PM2.5 (Co-Benefits) Analysis. As mentioned above, many of the 

steps EGUs 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 

work due to illness or the illness of a child is a particular 

problem for people who work jobs that do not provide paid sick 

days. Many 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 also 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 
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particularly susceptible to the health effects of PM2.5 and 

receive many benefits from reducing it. 

We estimate that in 2016 the annual PM related benefits of 

the final rule for adults include approximately 4,300 to 11,000 

fewer premature mortalities, 2,900 fewer cases of chronic 

bronchitis, 4,800 fewer non-fatal heart attacks, 2,700 fewer 

hospitalizations (for respiratory and cardiovascular disease 

combined), 3.2 million fewer days of restricted activity due to 

respiratory illness and approximately 550,000 fewer lost work 

days. We also estimate substantial health improvements for 

children in the form of 130,000 fewer asthma attacks, 3,200 

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. 

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 

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 have substantially higher risks of PM2.5-
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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 is large while the 

differences among races in both groups of counties are very 

small. In contrast, the analysis found that people with less 

than high school education have significantly greater risks 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 finds 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 (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 Appendix 5-C of the RIA. 

The EPA estimates that the benefits of the final rule are
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distributed among these populations fairly evenly. Therefore, 

there is no indication that people of particular race, income, 

or level of education receive a greater benefit (or smaller 

benefit) than others. 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 on the counties before implementation. 

These results are presented in more detail in Appendix 5-C 

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, 

implementation, and enforcement of environmental laws, 

regulations, and polices. 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 
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(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 hear comments on the 

proposal. 

Once this rule is finalized, affected EGUs will need to 

update their Title V operating permits to reflect their new 

emissions 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 these permit actions must include an 

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 requirements.

4. Summary

This final rule strictly limits the emissions rate of Hg 

and other HAP from every affected EGU in the EPA’s analysis 

indicates substantial health benefits, including for vulnerable 

populations, from reductions in PM2.5.

The EPA’s analysis also indicates reductions in risks for 
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individuals, including for members of many 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 

environmental effects on minority, low income, or indigenous 

populations. The EPA is providing multiple opportunities for EJ 

communities to both learn about and comment on this rule and 

welcomes their participation.

5. 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. This analysis can be found 

in Section 7.11 of the RIA. 

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 
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Page 697 of 984

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 698 of 984

DRAFT – DELIBERATIVE DOCUMENT – DO NOT CITE OR QUOTE

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: November 16, 2011.

____________________

Lisa P. Jackson,

Administrator.
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Page 699 of 984

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)(95) and (a)(96);

b. By redesignating paragraphs (a)(89) and (a)(90) as paragraphs 

(a)(93) and (a)(93);

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)(94) to read as follows:

§60.17 Incorporations by Reference.

* * * * *

(54) ASTM D3699 - 08, Standard Specification for Kerosene, 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 – 11, Standard Specification for Biodiesel Fuel 

Blend Stock (B100) for Middle Distillate Fuels, 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), IBR approved for §§60.41b of 

subpart Db of this part and 60.41c of subpart Dc of this part.

* * * * *

Subpart D-—[Amended]

3. The subpart heading for Subpart D is revised to read as 

follows:

Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam 

Generators

4. Section 60.40 is amended by revising paragraph (e) to read as 

follows:

§60.40 Applicability and designation of affected facility.

* * * * *

(e) Any facility covered under either subpart Da or KKKK is not 

covered under this subpart.

5. Section 60.41 is amended by adding the definitions of 

“natural gas” to read as follows:
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Page 701 of 984

Section 60.41 Definitions

* * * * *

Natural gas means:

(1) A naturally occurring mixture of hydrocarbon and 

nonhydrocarbon gases found in geologic formations beneath the 

earth’s surface, of which the principal constituent is methane; 

or

(2) Liquid petroleum gas, as defined by the American Society of 

Testing and Materials in ASTM D1835 (incorporated by reference, 

see §60.17); or

(3) A mixture of hydrocarbons that maintains a gaseous state at 

ISO conditions. Additionally, natural gas must either be 

composed of at least 70 percent methane by volume or have a 

gross calorific value between 34 and 43 megajoules (MJ) per dry 

standard cubic meter (910 and 1,150 Btu per dry standard cubic 

foot).

* * * * *

6. 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) 
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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 and operator of an affected facility that combusts 

only natural gas and that is subject to a federally enforceable 

permit limiting fuel use to 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 

emissions of SO2 or PM is exempt from the PM standards specified 

in paragraph a of this section.

7. Section 60.45 is amended as follows:

a. By revising paragraph (a).

b. By revising paragraph (b)(1) – (5).

c. By revising paragraph (b)(6).

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, 
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Page 703 of 984

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 

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 
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Page 704 of 984

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 SO2 and 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 

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 
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Page 705 of 984

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.

* * * * *

Subpart Da-—[Amended]

8. The subpart heading for Subpart Da is revised to read as 

follows:

Subpart Da—Standards of Performance for Electric Utility Steam 

Generating Units

9. Section 60.40Da is amended by revising paragraph (e) and by 

adding paragraph (f) to read as follows:

Section 60.40Da Applicability and designation of affected 

facility.

* * * * *

(e) Applicability of the requirement 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 
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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 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 

this part is not subject to the emission standards under subpart 

Da.

(f) General Duty to minimize emissions. At all times, the owner 

or operator 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 
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Page 707 of 984

procedures are being used will be based on information available 

to the 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.

10. Section 60.41Da is amended by revising the definitions of 

“gaseous fuel”, “integrated gasification combined cycle electric 

utility steam generating unit”, “petroleum” and “steam 

generating unit,” adding the definitions of “affirmative 

defense” and “petroleum coke,” and deleting the definitions of 

“dry flue gas desulfurization technology,” “emission rate 

period,” and “responsible official” to read as follows:

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 

merits of which are independently and objectively evaluated in a 

judicial or administrative proceeding.

* * * * *

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, 
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and gasified coal.

* * * * *

Integrated gasification combined cycle electric utility steam 

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.

* * * * *

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 

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 
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typically derived from oil refinery coker units or other 

cracking processes.

* * * * *

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 

cycle gas turbines; nuclear steam generators are not included) 

plus any integrated combustion turbines and fuel cells..

* * * * *

11. Section 60.42Da is to read as follows:

Section 60.42Da Standard for particulate matter (PM).

(a) Except as provided in paragraph (a)(4) 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 
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Page 710 of 984

affected facility for which construction, reconstruction, or 

modification commenced before March 1, 2005, any gases that 

contain filterable PM in excess of:

(1) 13 ng/J (0.03 lb/MMBtu) heat input;

(2) 1 percent of the potential combustion concentration (99 

percent reduction) when combusting solid fuel; and

(3) 30 percent of potential combustion concentration (70 percent 

reduction) when combusting liquid fuel.

(4) An owner or operator of an affected facility that 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 does not use a post-combustion technology to reduce 

emissions of SO2 or PM is exempt from the PM standard specified 

in paragraphs (a)(1), (a)(2), and (a)(3) of this section:

(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) Owners and operators of an affected facility that elect to 
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Page 711 of 984

install, calibrate, maintain, and operate a continuous emissions 

monitoring system (CEMS) for measuring PM emissions according to 

the requirements of this subpart are 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 (e) 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 filterable 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.

(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. For an 
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Page 712 of 984

affected facility that commenced construction, reconstruction, 

or modification, 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 discharged into the atmosphere from that affected 

facility any gases that contain filterable PM in excess of:

(1) 13 ng/J (0.030 lb/MMBtu) heat input, 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) An owner or operator of an affected facility than 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 post-combustion technology to 

reduce emissions of SO2 or PM is exempt from the PM standard 

specified in paragraphs (c) of this section.

(f) Except as provided in paragraph (g) of this section, on and 
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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, modification, or reconstruction 

after May 3, 2011, shall cause to be discharged into the 

atmosphere from that affected facility any gases that contain 

total PM in excess of either:

(1) For an affected facility that commenced construction or 

reconstruction 7.0 ng/J (0.055 lb/MWh) gross energy output; or

(2) For an affected facility that commenced modification, 15 

ng/J (0.034 lb/MMBtu) heat input.

(g) An owner or operator of an affected facility that combusts 

only natural gas is exempt from the total PM standard specified 

in paragraph (f) of this section.

(h) The PM emission standards under this section do not apply to 

an owner or operator of any affected facility that is operated 

under a PM commercial demonstration permit issued by the 

Administrator in accordance with the provisions of §60.47Da.

12. Section 60.43Da is amended as follows:

a. By revising paragraph (a).

b. By revising paragraph (f).

c. By revising paragraph(i).

d. By revising paragraph (j).
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e. By revising paragraph (k).

f. By adding paragraph (l).

g. By adding paragraph (m).

h. By adding paragraph (n).

Section 60.43Da Standard 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 

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 
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Page 715 of 984

facility that commenced 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 emission limitation 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).

(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).
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(j) 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 

commenced after February 28, 2005, but before May 4, 2011, and 

that burns 75 percent or more (by heat input) coal refuse on a 

12-month rolling average basis, shall caused to be discharged 

into the atmosphere from that affected facility any gases that 

contain SO2 in excess of the applicable emission limitation 

specified in paragraphs (j)(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) 6 percent of the potential combustion concentration (94 

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) 6 percent of the potential combustion concentration (94 

percent reduction).

(3) For an affected facility which commenced modification, any 

gases that contain SO2 in excess of either:
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Page 717 of 984

(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 non-continental area that commenced 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 emission limitation 

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 

excess of 230 ng/J (0.54 lb/MMBtu) heat input.

(l) Except as provided in paragraphs (m) and (n) of this 

section, on and after the date on which the initial performance 
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Page 718 of 984

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 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 emission 

limitation specified in paragraphs (l)(1) or (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) 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 

date comes first, no owner or operator of an affected facility 

that commenced construction, reconstruction, or modification 

commenced after May 3, 2011, and that burns 75 percent or more 
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(by heat input) coal refuse on a 12-month rolling average basis, 

shall caused to be discharged into the atmosphere from that 

affected facility any gases that contain SO2 in excess of the 

applicable emission limitation specified in paragraphs (m)(1) or 

(2) of this section.

(1) For an affected facility which commenced construction or 

reconstruction, any gases that contain SO2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output; or

(ii) 6 percent of the potential combustion concentration (94 

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).

(n) 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 non-continental area that commenced 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 emission limitation specified in paragraphs (n)(1) 
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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.

13. Section 60.44Da is amended as follows:

a. By revising paragraph (a).

b. By revising paragraph (b).

c. By revising paragraph (d).

d. By revising paragraph (e).

e. By revising paragraph (f).

f. By adding paragraph (g).

g. By adding paragraph (h).

Section 60.44Da Standard for nitrogen oxides (NO).

(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 subject to the provisions 

of this subpart shall cause to be discharged into the atmosphere 

from any affected facility, except as provided under paragraphs 
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(b), (d), (e), and (f) of this section, any gases that contain 

NOX (expressed as NO2) in excess of the following emission 

limits:

* * * * *

(b) The NOX emission limitations 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.

* * * * *

(d)(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 of an affected 

facility that commenced construction after July 9, 1997, but 

before March 1, 2005, shall cause to be discharged into the 

atmosphere any gases that contain NOX (expressed as NO2) in 

excess of 200 ng/J (1.6 lb/MWh) gross energy output, except as 

provided under §60.48Da(k).

(2) 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 affected facility for 

which reconstruction commenced after July 9, 1997, but before 

March 1, 2005, shall cause to be discharged into the atmosphere

any gases that contain NOX (expressed as NO2) in excess of 65 
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ng/J (0.15 lb/MMBtu) heat input.

(e) 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, 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 emission limitation specified in paragraphs (e)(1) 

through (3) of this section.

(1) For an affected facility which commenced construction, any 

gases that contain NOX (expressed as NO2) in excess of 130 ng/J 

(1.0 lb/MWh) gross energy output, except as provided under 

§60.48Da(k).

(2) For an affected facility which commenced reconstruction, any 

gases that contain NOX (expressed as NO2) 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 (expressed as NO2) 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.
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(f) 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 (f)(1) 

through (3) of this section.

(1) Except as provided for in paragraphs (f)(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 

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 (f)(2) of this section for 

only a portion of the clock hours in the 30-day period, the 
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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 

(f)(1) and (2) of this section.

(g) Compliance with the emission limitations under this section 

are determined on a 30 boiler operating day rolling average 

basis, except as provided under §60.48Da(j)(1).

(h) 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 88 ng/J (0.70 lb/MWh) gross 

energy output.

14. Section 60.45Da is amended by deleting paragraphs (a) and 

(b), and reserving the section.

Section 60.45Da Standard for mercury (Hg).

15. Section 60.47Da is amended as follows:

a. By adding paragraph (f).

b. By adding paragraph (g).
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c. By adding paragraph (h).

d. By adding paragraph (i).

Section 60.47Da Commercial demonstration permit.

* * * * *

(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 15 ng/J (0.034 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 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 

controls system or advanced combustion controls who is issued a 
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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 

less than 130 ng/J (1.0 lb/MWh) gross 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.

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

16. Section 60.48Da is amended as follows:

a. By revising paragraph (c).

b. By revising paragraph (g).

c. By revising paragraph (k)(1)(i).

d. By revising paragraph (k)(1)(ii).

e. By revising paragraph (k)(2)(i).
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f. By revising paragraph (k)(2)(iv).

g. By removing and reserving paragraph (l)

h. By revising paragraph (n).

i. By revising paragraph (p).

j. By adding paragraph (r).

Section 60.48a Compliance provisions.

* * * * *

(c) For affected facilities that commenced construction, 

modification, or reconstruction before May 4, 2011, the PM 

emission standards under §60.42Da, and the NOX emission standards 

under §60.44Da apply at all times except during periods of 

startup, shutdown, or malfunction. The sulfur dioxide emission 

standards under §60.43Da apply at all times except during 

periods of startup, shutdown, or when both emergency conditions 

exist and the procedures under paragraph (d) of this section are 

implemented. For affected facilities that commence construction, 

modification, or reconstruction after May 3, 2011, the PM 

emission standards under §60.42Da, the NOX emission standards 

under §60.44Da, and the sulfur dioxide emission standards under 

§60.43Da apply at all times. 

* * * * *

(g) The owner or operator of an affected facility subject to 

emission limitations in this subpart shall determine compliance 
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as follows:

(1) For affected facilities that commenced construction, 

modification, or reconstruction before May 4, 2011, compliance 

with applicable 30 boiler operating day rolling average SO2 and 

NOX emission limitations 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, malfunction (NOX only), or 

emergency conditions (SO2 only). For affected facilities that 

commence construction, modification, or reconstruction after May 

3, 2011, compliance with applicable 30 boiler operating day 

rolling average SO2 and NOX emission limitations is determined by 

dividing the sum of all the SO2 and NOX emissions for the 30 

successive boiler operating days divided by the sum of all the 

gross useful output for the 30 successive boiler operating days.

(2) For affected facilities that commenced construction, 

modification, or reconstruction 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 that commence construction, modification, or 

reconstruction after May 3, 2011, compliance with applicable SO2

percentage reduction requirements is determined based on the “as 
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fired” total potential emissions and the total outlet SO2

emissions for the 30 successive boiler operating days.

(3) For affected facilities that commenced construction, 

modification, or reconstruction before May 4, 2011, compliance 

with applicable daily average PM emission limitations 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. For affected 

facilities that commence construction, modification, or 

reconstruction after May 3, 2011, compliance with applicable 

daily average PM emission limitations is determined by 

calculating dividing the sum of all PM emissions for PM each 

boiler operating day divided by the sum of all the gross useful 

output for PM each boiler operating day, except for data 

obtained during malfunction. 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-out-of-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-of-control hourly emission rates of the 

next boiler operating day with 18 hours or more of non-out-ofcontrol PM CEMS data to determine compliance.
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* * * * *

(k) * * *

(1) * * *

(i) The emission rate (E) of NOX shall be computed using Equation 

2 in this section:

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/MWh) 

gross 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/hr (dscf/hr);

Qte = Average hourly volumetric flow rate of exhaust gas from 

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combustion turbine, dscm/hr (dscf/hr);

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:

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/MWh) 

gross output;

Csg = Average hourly concentration of NOX exiting the steam 

generating unit, ng/dscm (lb/dscf);

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the red x still appears, you may have to delete the image and then insert it again.
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Qsg = Average hourly volumetric flow rate of exhaust gas from 

steam generating unit, dscm/hr (dscf/hr); 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/hr) 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:

Where:

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appears, you may have to delete the image and then insert it again.
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E = Emission rate of NOX from the duct burner, ng/J (lb/MWh) 

gross 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/hr (MMBtu/hr); and

Occ = Average hourly gross energy output from entire combined 

cycle unit, J/h (MW).

* * * * *

(n) Compliance provisions for sources subject to §60.42Da(c)(1). 

The owner or operator of an affected facility subject to 

§60.42Da(c)(1) 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 divided by the average hourly gross energy 

output (measured according to the provisions of §60.49Da(k)).

* * * * *

(p) * * *

(5) At a minimum, non-out-of-control valid CEMS hourly averages 

shall be obtained for 75 percent of all operating hours on a 30 
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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 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) Affirmative Defense for Exceedance of Emission Limit During

Malfunction. In response to an action to enforce the standards 

set forth in paragraph §§60.42Da, 60.43Da, and 60.44Da, you may 
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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. 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 (b) 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 

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 emission limitations were being exceeded. Off-shift 
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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

(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 
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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) The owner or operator of the facility 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, 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 standards in §§60.42Da, 60.43Da, and 

60.44Da 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.
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* * * * *

17. 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).

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 removing and reserving paragraph (u).

Section 60.49Da Emission monitoring.

(a) * * * 

(1) Except as provided for in paragraph (a)(2) 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 
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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 

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; or

(A) No post-combustion technology (except a wet scrubber) is 

used for reducing PM, SO2, or carbon monoxide (CO) emissions;
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(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 

(u) of this section.

(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.

* * * * *

(b) The owner or operator of an affected facility shall install, 

calibrate, maintain, and operate a CEMS, and record the output 
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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, 

malfunction, and emergency conditions, 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 output for sources 

demonstrating compliance with an output-based standard.

* * * * *

(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 
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meeting the requirements of Performance Specification (PS) 6 of 

appendix B of this part and the CD assessment, 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 

emission limitation 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) * * *

(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).
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* * * * *

(4) As of January 1, 2012, and within 60 days after the date of 

completing each performance test, as defined in §63.2, 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.

18. Section 60.50Da is amended as follows:

a. By revising paragraph (b).

b. By removing paragraph (g).

c. By removing paragraph (h).

d. By removing paragraph (i).

Section 60.50Da Compliance determination procedures and 

methods.

* * * * *

(b) * * *

(2) For the filterable particular matter concentration, Method 5 

of appendix A of this part shall be used at affected facilities 
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without wet FGD systems and Method 5B of appendix A of this part 

shall be used after wet FGD systems.

* * * * *

(4) Total particular matter concentration consists of the sum of 

the filterable and condensable fractions. The condensable 

fraction shall be measured using Method 202 of appendix M of 

part 51, and the filterable fraction shall be measured using 

Method 5 of appendix A of this part.

* * * * *

19. Section 60.51Da is amended as follows:

a. By revising paragraph (a).

b. By removing and reserving paragraph (g).

c. By revising paragraph (k).

Section 60.51 Da Reporting requirements.

(a) For SO2, NOX, and PM emissions, the performance test data 

from the initial and subsequent performance test and from the 

performance evaluation of the continuous monitors (including the 

transmissometer) are submitted to the Administrator.

* * * * *

(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 
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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 

was achieved during the reporting period.

20. Section 60.52Da is amended by removing and reserving 

paragraph (a).

Section 60.52Da Recordkeeping requirements.

* * * * *

Subpart Db-—[Amended]

21. 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).

Section 60.40b Applicability and delegation of affected 

facility.

* * * * *

(c) Affected facilities that also meet the applicability 

requirements under subpart J or subpart Ja (Standards of 

performance for petroleum refineries) are subject to the PM and 
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NOX standards under this subpart and the SO2 standards under 

subpart J or subpart Ja.

* * * * *

(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 

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/hr) 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 
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this subpart and the PM standards under subpart BB.

* * * * *

22. Section 60.41b is amended by revising the definition of 

“distillate oil” to read as follows:

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), kerosene, 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).

* * * * *

23. Section 60.44b is amended by revising paragraphs (c) and (d) 

to read as follows:

Section 60.44b Standard for nitrogen oxides (NO).
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* * * * *

(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, or a mixture 

of these fuels with natural gas, and wood, municipal-type solid 

waste, 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 or oil, or mixtures of these fuels with 

natural gas combusted in the affected facility, as determined 

pursuant to paragraph (a) or (b) of this section, unless the 

affected facility has an annual capacity factor for coal or oil, 

or mixture of these fuels with natural gas 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 coal, oil, or a 

mixture of these fuels with natural gas.

(d) 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 natural gas or distillate 

oil with a potential SO2 emissions rate of 26 ng/J (0.060 
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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.

* * * * *

24. 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 60 days after the date of 

completing each performance test, as defined in §63.2, 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 
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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.

25. 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).

Section 60.48b. Reporting and recordkeeping requirements.

(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 

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 
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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;

 * * * * *

(j) The owner or operator of an affected facility that meets the 

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:

* * * * *
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(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.

* * * * *

Subpart Dc-—[Amended]

26. Section 60.40c is amended as follows:

a. By revising paragraph (e).

b. By revising paragraph (f).

c. By revising paragraph (g).

Section 60.40c Applicability and delegation of authority
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* * * * *

(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/hr) heat input 

of fossil fuel but less than or equal to 29 MW (100 MMBtu/hr) 

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 

stationary combustion turbine emissions are subject to subpart 

GG or KKKK, as applicable, of this part).

(f) Any 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 of 

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.

27. Section 60.41c is amended by removing the definition of 
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“Cogeneration” and revising the definition of “Distillate oil” 

to read as follows:

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 

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), 

kerosene, 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).

* * * * *

28. Section 60.42c is amended as follows:

a. By revising paragraph (d).

b. By revising paragraph (h) introductory text.

c. By revising paragraph (h)(3).

d. By adding paragraph (h)(4).
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Section 60.42c Standard for sulfur dioxide (SO2).

* * * * *

(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 

SO2in 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.

* * * * *

(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 

based on a certification from the fuel supplier, as described 

under §60.48c(f), as applicable.

* * * * *

(3) Coal-fired affected facilities with heat input capacities 

between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).

(4) Other fuels-fired affected facilities with heat input 
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capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).

* * * * *

29. Section 60.45c is amended by revising paragraph (c)(14) to 

read as follows:

Section 60.45c Compliance and performance test methods and 

procedures for particulate matter.

* * * * *

(c)(14) As of January 1, 2012, and within 60 days after the date of 

completing each performance test, as defined in §63.2, 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.

* * * * *

30. Section 60.47c is amended as follows:

a. By revising paragraph (a).

b. By revising paragraph (f).

c. By revising paragraph (g).
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d. By revising paragraph (h).

Section 60.47c Emission monitoring for particulate matter.

(a) Except as provided in paragraphs (c), (d), (e), (f), (g), 

and (h) of this section, the owner or operator of an affected 

facility combusting coal, oil, or wood that is subject to the 

opacity 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), (f), or (g) 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 
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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;

* * * * *

(f) Owners and operators of an affected facility that is subject 

to an opacity standard in §60.43c(c) and that 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 is not required to operate a COMS.

(g) 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.

(h) Owners and operators of an affected facility that is subject 

to an opacity standard in §60.43c(c) and that burns only gaseous 

fuels and/or fuel oils that contain less than or equal to 0.5 

weight percent sulfur and operates according to a written site-
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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.

Subpart HHHH-—[Amended]

31. Subpart HHHH is removed and reserved.
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PART 63 -- [AMENDED]

32. The authority citation for part 63 continues to read as 

follows:

Authority: 42 U.S.C. 7401, et seq.

33. 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

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?

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?

63.10007 What methods and other procedures must I use for the 

performance tests?

63.10009 May I use emission averaging to comply with this 

subpart?
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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 

emission averaging provision?

63.10023 How do I establish my PM CPMS operating limit and 

determine compliance with it?

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
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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 

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 one 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 
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existing coal- or oil-fired EGUs as defined in §63.10042.

(2) The affected source of this subpart is each new or 

reconstructed coal- or oil-fired EGU as defined in §63.10042 and 

specified in §63.9985 of this subpart.

(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 

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 utility steam generating unit that has 

switched completely to burning a different coal rank or fuel 

type is considered to be an existing affected source under this 

subpart.

§63.9983 Are any electric utility steam generating units 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), 
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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 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 

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 utility steam generating unit combusting solid 

waste and listed as an affected source in any standard(s) 

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, 
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whichever is later.

(b) If you have an existing EGU, you must comply with this 

subpart no later than [INSERT DATE 3 YEARS 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.

(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 AFTER THIS FINAL RULE IS 

PUBLISHED IN THE FEDERAL REGISTER] for existing sources must 

comply with the applicable new or 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 and 

would be subject to this subpart except for the exemption in § 

63.9983(d) for commercial and industrial solid waste 

incineration units covered by part 60, subpart CCCC or subpart 

DDDD, or any other part 60 standard issued pursuant to CAA 

sections 129 and 111, you must be in compliance with this 
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subpart on [INSERT DATE 3 YEARS AFTER THIS FINAL RULE IS 

PUBLISHED IN THE FEDERAL REGISTER] or on the effective date of 

the switch from waste to fuel as provided for in part 60, 

subpart CCCC or subpart DDDD, whichever is later.

§63.9985 What is a new EGU?

(a) A new EGU is an EGU that meets any of the criteria specified 

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 > 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)(3) of this section and as defined in 

§63.10042.

(1) Continental liquid oil-fired EGUs

(2) Non-continental liquid oil-fired EGUs, and

(3) EGUs designed to burn solid oil-derived fuel.
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(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 

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 paragraph 

(a)(1)(i) and (ii) or under §63.10009.

(i) You may not use the alternate SO2 limit if your coal-fired 

EGU does not have a system using wet or dry flue gas 

desulfurization technology installed on the unit.

(ii) You may not use the alternate SO2 limit if your oil-fired 

EGU does not have a system using wet or dry flue gas 

desulfurization technology installed on the unit.

(iii) You must operate the wet or dry flue gas desulfurization 

technology installed on the unit at all times in order to 

qualify to use the alternate SO2 limit.

(2) You must meet each operating limit in Table 4 to this 
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subpart that applies to your EGU. 

(b) As provided in §63.6(g), EPA may approve use of an 

alternative to the work practice standards in this section.

General Compliance Requirements

§63.10000 What are my general requirements for complying with 

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 or solid oil derived-fired EGUs, you are 

required to meet the work practice requirements in Table 3 

during periods of cold 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 
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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 

accordance with §63.10005(k), 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 or

(B) You may not pursue the LEE option for Hg if your coal-fired 

or oil-fired EGU or IGCC EGU is new. 

(iii) For a qualifying LEE for Hg emissions limits, you must 

conduct a 30-day performance test using Method 30B at least once 

every 12 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 months to 

demonstrate continued LEE status. 

(iv) If your coal-fired or solid oil-derived fuel-fired EGU does 

not qualify as a LEE for total non-mercury HAP metals, 

individual non-mercury HAP metals, or filterable particulate 
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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) or compliance performance testing 

repeated monthly. If you elect to use PM CPMS, you will 

establish a site-specific 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. 

(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 a 

periodic monthly performance stack test for HCl. If your EGU 

uses wet or dry flue gas desulfurization technology (this 
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includes limestone injection into a fluidized bed 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, 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 

initial performance testing in accordance with §63.10005(k), 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 months to demonstrate continued LEE status. For a 

qualifying LEE of any other applicable emissions limits, you 

must conduct a performance test at once every 36 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 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) or performance testing conducted 

quarterly. If you elect to use PM CPMS, you will establish a 

site-specific 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. 

(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 

alternative to HCl CEMS, HF CEMS, or HCl and HF CEMS, you may 

demonstrate initial and continuous compliance by conducting a 
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periodic quarterly performance stack test for HCl and by 

continuously monitoring an acid gas control device parameter. If 

your EGU uses wet or dry flue gas desulfurization technology 

(this includes limestone injection into a fluidized bed 

combustion unit), you may apply a second alternative to HCl 

CEMS, HF CEMS, or HCl and HF 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. As a third alternative, you may 

measure or obtain, as well as keep records of, fuel moisture 

content; as long as fuel moisture does not exceed 1.0 percent, 

you need not conduct other HCl or HF monitoring or testing.

(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 

you petition the EPA Administrator for alternative monitoring 

parameters under §63.8(f). This requirement to develop and 

submit a site-specific monitoring plan does not apply to 
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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 to this 

subpart; and 

(ii) The recordkeeping and reporting requirements of part 75 of 

this chapter or appendix A to this subpart that pertain 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 
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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(i).

(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.

(iv) Performance evaluation procedures and acceptance criteria 

(e.g., calibrations), including ongoing data quality assurance 

procedures in accordance with the general requirements of 
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§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). 

(e) As part of your demonstration of continuous compliance, you 

must perform periodic tune-ups of your EGU(s), according to 

§63.10021(a)(11). 

(f) You are subject to the requirements of this subpart 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, 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) 
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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 §63.10000(a)(2). 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, 

whichever is earlier.

(h) If you own or operate an EGU that does not meet the 

definition of an EGU subject to this subpart, and you commence 

or recommence operations that cause you to meet the definition 
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of an EGU subject to this subpart, you are subject to the 

provisions of this subpart 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 before you commence or recommence 

operations that cause you to meet the definition of an EGU 

subject to this subpart.

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 or part 63 subpart and 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 
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operations that will cause your unit to meet the definition of 

an EGU subject to this subpart, consistent with (2) and (3)) 

above.

(i) If you own or operate an EGU subject to this subpart, and it 

has been (or will be) 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 select the date on which your EGU will 

no longer be subject to this subpart. You must complete all 

initial compliance demonstrations for any CAA section 112 or 129 

standards that are applicable to your facility before you 

commence compliance with any newly applicable standards.

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 

with this subpart, and the date of the notice;

(ii) The currently applicable subcategory under this subpart, 

and any 40 CFR part 60 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 (2) and (3)) above.
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(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 

must also comply with provisions of §§63.10010, 10020, and 10021 

of this subpart. Relative accuracy tests must be performed as of 

the performance test deadline for PM CEMS. 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.
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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 

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
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(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

(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 
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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, 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 
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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 

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 (g), (h), or (j) of this section. 

(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 
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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 

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 or HCl or HF 

CEMS or a sorbent trap monitoring system) or an SO2 CEMS, you 

must conduct an initial performance test consisting of 30 

operating days of valid data collected with the certified

monitoring system. 

(i) The 30 operating day CMS performance test must demonstrate 

compliance with the applicable Hg, HCl, HF, or SO2 emissions 

limit in Table 1 or 2 to this subpart.

(iii) 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 
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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 your 

compliance clock starts (as specified in §63.9984), 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 months prior to the date on which 

your compliance clock starts;

(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 
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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 as part of your initial compliance 

demonstration.

(d) CMS Requirements. If, for a particular pollutant or 

surrogate, 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 Appendix B to this 

rule. Initial compliance is achieved if the arithmetic average 

of 30 operating days of quality-assured CEMS data, expressed in 
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units of the standard (see §63.10007(e)), meets the applicable 

SO2, 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 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 paragraph (g), (h), or (j) of this 

section.

(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 

selected pollutant emissions limit and reassess and adjust the 

site-specific operating limit in accordance with the results of 
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the performance test. 

(4) 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 paragraph (g), 

(h), or (j) of this section. Initial compliance is achieved if 

the arithmetic average of 30 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. 

(f) 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).

(g) For existing affected sources a tune-up may occur prior to 

the effective date, so that existing sources have up to 42 

months (3 years 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 the effective date, the source must 
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maintain adequate records to show that the tune-up met the 

requirements of this standard.

(h) 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).

(i) For the new or reconstructed affected source described in 

paragraph (h) of this section, 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.

(j) 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 
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source.

(k) Low emitting EGUs. The provisions of this paragraph (k) 

apply to pollutants with emissions limits except Hg from new 

EGUs 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, total non-Hg HAP metals, or individual non-Hg HAP 

metals if you collect initial performance test data that meet 

the requirements of this paragraph (k) and (if applicable) 

paragraph (l) of this section, and if those data demonstrate:

(i) For all pollutants except Hg, average emissions less than 50 

percent of the applicable emissions limit in Table 1 or 2 to 

this subpart; 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 22.0 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 the initial 

performance tests described in §63.10007 to demonstrate that a 

unit qualifies for LEE status, except that the required minimum 

sampling volume must be increased nominally by a factor of two. 

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 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 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 

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 22.0 lb/year, you will have to collect some or all of the 
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following data during the 30 day test period (see paragraph 

(k)(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 

flow rate, and/or moisture, record hourly average values of each 

parameter throughout the 30 operating day test period. If you 

opt to use EPA reference methods rather than CEMS for any 
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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 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 and replacing the hourly value of “th” with the number of 

hours in 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 

according to paragraph (k)(3)(iii)(A) of this section) by the 

maximum potential annual heat input to the unit (TBtu), which is 
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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 (k)(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 (k)(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 

single emission test in the common stack. If you choose the 

common stack testing option, the units in the configuration 
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qualify for LEE status if:

(i) The average emission rate measured at the common stack is 

less than 50 percent (10 percent for Hg) of the applicable Hg 

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 (k)(3)(iii) of 

this section (with some modifications), are less than or equal 

to 22.0 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 average 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 subpart; or

(ii) -For Hg from an existing EGU, the applicable Hg emission 
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limit in Table 2 to this subpart is met and the potential annual 

mass emissions, calculated according to paragraph (k)(3)(iii) of 

this section, are less than or equal to 22.0 pounds. Use the 

average Hg emission rate from paragraph (k)(6)(i) of this 

section in your calculations.

(1) If your EGU combusts liquid fuels, if your fuel moisture 

content is no greater than 1.0 percent, and if you would like to 

demonstrate initial and ongoing compliance with HCl and HF 

emissions limits, you must

(A) Measuring fuel moisture content of each shipment of 

fuel if your fuel arrives on a batch basis;

(B) Measuring fuel moisture content daily if your fuel 

arrives on a continuous basis; or

(C) Obtaining and maintaining a fuel moisture certification 

from your fuel supplier. 

(2) Should the moisture in your liquid fuel be more than 

1.0 percent, you must 

(A) Conduct HCl and HF emissions testing quarterly and 

monitor acid gas control device parameters continuously or

(B) Use an HCl CEMS and/or HF CEMS.

(m) Startup and Shutdown for coal-fired or solid oil derivedfired units. You must follow the requirements given in Table 3.
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(n) 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 solid oil-derived fuel- and coal-fired EGUs using PM 

CPMS as the compliance method for either the total non-Hg HAP 

metals emissions limit or the individual non-Hg HAP metals 

emissions limits, 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 

§63.1005(k), you must repeat the performance test once every 3 

years 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:

(i) For all pollutants or surrogates except for Hg, you must 

initiate periodic emissions testing every three months.

(ii) 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 six months of losing LEE 

eligibility. Until the Hg CEMS or sorbent trap monitoring system 

is installed, certified, and operating, you must conduct Hg 
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emissions testing every three months.

(c) For liquid oil-fired EGUs, you must conduct all applicable 

performance tests for individual or total non-Hg HAP metals 

emissions according to Table 5 and §63.10007 at least every 

three months.

(d) For solid oil-derived fuel- and coal-fired EGUs without SO2

CEMS used as the compliance method for HCl or without installed 

systems that use wet or dry flue gas desulfurization technology, 

you must conduct all applicable performance tests HCl emissions 

according to Table 5 and §63.10007 at least every 3 months.

(e) For solid oil-derived fuel- and coal-fired EGUs without HCl 

CEMS you must conduct all applicable performance tests for HCl 

emissions according to Table 5 and §63.10007 at least every 

three months.

(f) For liquid oil-fired EGUs without HCl CEMS, HF CEMS, or HCl 

and HF CEMS, you must conduct all applicable performance tests 

for HCl, HF, or HCl and HF emissions according to Table 5 and 

§63.10007 at least every three months.

(g) Unless you follow the requirements listed in paragraphs (h) 

through (j) of this section, performance tests required at least 

every 5 years must be completed within 58 to 62 months after the 

previous performance test; performance tests required at least 

every 3 years must be completed within 35 to 37 months after the 
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previous performance test; performance tests required at least 

every year must be completed no more than 13 months after the 

previous performance test; and performance tests required at 

least every 3 months must be completed between 83 and 99 days 

after the previous performance test.

(h)If you elect to demonstrate compliance using emission 

averaging under §63.10009, you must continue to conduct 

performance stack tests at the appropriate frequency given in 

section (c) through (f) of this paragraph.

(i) If a performance test on a non-Hg LEE shows emissions in 

excess of 50 percent of the emission limit, you must conduct 

performance tests at the appropriate frequency given in section 

(c) through (f) of this paragraph for that pollutant until all 

performance tests over a consecutive 3-year period show 

compliance.

(j) 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 months after 

the previous performance tune-up.

(2) For EGUs employing neural network combustion optimization 
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systems during normal operation, each performance tune-up 

specified in §63.10021(e) must be no more than 48 months after 

the previous performance tune-up. 

(k) 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).

(b) You must conduct each performance test (including 

traditional 3-run stack tests, 30 operating day tests based on 

CEMS data (or sorbent trap monitoring system data), and 30 

operating day Hg emission tests for LEE qualification) according 

to the requirements in Table 5 to this subpart.

(c) You must conduct performance tests under normal operating 

conditions. If you choose to comply with the filterable PM 

emission limit and demonstrate continuous compliance using a PM 

CPMS, you must also establish an operating limit according to 
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§63.10011(b)(5) and Tables 4 and 6 to this subpart. Should you 

desire to have operating limits that correspond to loads other 

than 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), (e) and (k), 

respectively, provide special instructions for conducting 

performance tests based on CEMS, 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) 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 
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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 1.660 x 10-7;

(ii) Multiply HCl and HAP metals concentrations (mg/dscm) by 

6.24 x 10-8; and

(iii) Multiply Hg concentrations (μg/scm) by 6.24 x 10-11.

(2) To determine compliance with emission limits expressed in 

lb/MWh or lb/GWh, you must first calculate the pollutant mass 

emission rate, in units of lb/hr, 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 1.66 x 10-

7 lb/scf-ppm for SO2 or 9.43 x 10-8 lb/scf-ppm for HCl, and 

defining Ch as the hourly average SO2 or HCl concentration in 

ppm. This calculation requires stack gas volumetric flow rate 

and (in some cases) moisture content data (see 

§§63.10005(k)(3)(i) and 63.10010). Then, use Equation A-4 in 

appendix A to this subpart to calculate the pollutant emission 

rate in lb/GWh. To express the applicable emissions limit in 

units of lb/MWh, divide the result from Equation A-4 by 103.
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(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.

§63.10009 May I use emission averaging to comply with this 

subpart?

(a) As an alternative to meeting the requirements of §63.9991 

for PM, HF, HCl, non-Hg HAP metals, or Hg on an EGU-specific 

basis, if 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), you may demonstrate compliance by emission averaging 

among the existing EGUs in the same subcategory, if your 

averaged emissions for such EGUs are equal to or less than the 

applicable emission limit, according to the procedures in this 

section.

(b) 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 PM, HF, HCl, non-Hg HAP metals, 

or Hg emissions to demonstrate compliance with the limits in 

Table 2 to this subpart if you satisfy the requirements in 

paragraphs (c), (d), (e), (f), and (g) of this section.
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(c) For each existing EGU in the averaging group, the emission 

rate achieved during the initial compliance test for the HAP 

being averaged must not exceed the emission level that was being 

achieved on [INSERT DATE 30 DAYS AFTER PUBLICATION OF THIS FINAL 

RULE IN THE FEDERAL REGISTER] or the control technology employed 

during the initial compliance test must not be less effective 

for the HAP being averaged than the control technology employed 

on [INSERT DATE 30 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN 

THE FEDERAL REGISTER].

(d) The averaged 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 in §63.9984.

(e) You must 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.

(1) You must use Equation 1 of this section to demonstrate that 

the PM, HF, SO2, HCl, non-Hg HAP metals, or Hg emissions from all 

existing units participating in the emissions averaging option 

do not exceed the emission limits in Table 2 to this subpart.
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Where:

Ave Weighted Emissions = Average weighted emissions for PM, HF, 

SO2, HCl, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu 

for Hg) of heat input.

Er = Emissions rate (as determined during the most recent 

performance test, according to Table 5 to this subpart) for PM, 

HF, HCl, non-Hg HAP metals, or Hg for unit, i, for PM, HF, SO2, 

HCl, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for 

Hg) of heat input.

Hm = Maximum rated heat input capacity of unit, i, in units of 

million Btu per hour.

n = Number of units participating in the emissions averaging 

option.

(2) If you are not capable of monitoring heat input, and the EGU 

generates steam for purposes other than generating electricity, 

you may use Equation 2 of this section as an alternative to 

using Equation 1 of this section to demonstrate that the PM, HF, 

HCl, non-Hg HAP metals, and Hg emissions from all existing units 

participating in the emissions averaging option do not exceed 

the emission limits in Table 2 to this subpart.

Where:

Ave Weighted Emissions = Average weighted emission level for PM, 

HF, HCl, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu 

for Hg) of heat input.

Er = Emissions rate (as determined during the most recent 

performance test, according to Table 5 to this subpart) for PM, 

HF, HCl, non-Hg HAP metals, or Hg for unit, i, for PM, HCl, HF, 

HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat 

input.
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Sm = Maximum steam generation by unit, i, in units of pounds.

Cf = Conversion factor, calculated from the most recent 

compliance test, in units of million Btu of heat input per 

pounds of steam generated for unit, i.

n = Number of units participating in the emissions averaging 

option.

(f) You must demonstrate compliance on a quarterly basis 

determined at the end of every three months (4 times per year) 

according to paragraphs (f)(1) through (3) of this section. The 

first quarterly period begins on the compliance date specified 

in §63.9984.

(1) For each quarter, you must use Equation 3 of this section to 

calculate the quarterly average weighted emission rate using the 

actual heat capacity for each existing unit participating in the 

emissions averaging option.

Where:

Ave Weighted Emissions = Quarterly average weighted emission 

level for PM, HCl, HF, non-Hg HAP metals, or Hg, in units of 

lb/MMBtu (lb/TBtu for Hg) of heat input.

Er = Emissions rate, (as determined during the most recent 

performance test, according to Table 5 to this subpart) for PM, 

HCl, HF, non-Hg HAP metals, or Hg for unit, i, for PM, HCl, HF, 

non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) 

of heat input.

Hb = The average heat input for each calendar month of EGU, i, 

in units of million Btu.

n = Number of units participating in the emissions averaging 

option.
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(2) If you are not capable of monitoring heat input, you may use 

Equation 4 of this section as an alternative to using Equation 3 

of this section to calculate the monthly weighted emission rate 

using the actual steam generation from the units participating 

in the emissions averaging option.

Where:

Ave Weighted Emissions = Monthly average weighted emission level 

for PM, HCl, HF, HAP metals, or Hg, in units of lb/MMBtu 

(lb/TBtu for Hg) of heat input.

Er = Emissions rate, (as determined during the most recent 

performance test, as calculated according to Table 5 to this 

subpart) for PM, HCl, HF, non-Hg HAP metals, or Hg for unit, i, 

for PM, HCl, HF, non-Hg HAP metals, or Hg, in units of lb/MMBtu 

(lb/TBtu for Hg) of heat input.

Sa = Actual steam generation for each calendar month by EGU, i, 

in units of pounds.

Cf = Conversion factor, as calculated during the most recent 

compliance test, in units of million Btu of heat input per 

pounds of steam generated for unit, i.

n = Number of units participating in the emissions averaging 

option.

(3) Until 4 quarterly weighted average emission rates have been 

accumulated, calculate and report only the quarterly average 

weighted emission rate determined under paragraph (f)(1) or (2) 

of this section. After 4 quarterly weighted average emission 

rates have been accumulated, for each subsequent calendar month, 

use Equation 5 of this section to calculate the 12-month rolling 

average of the quarterly weighted average emission rates for the 
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current quarter and the previous 3 quarters.

Where:

Eavg = 12-month rolling average emissions rate, (lb/MMBtu heat 

input; lb/TBtu for Hg).

ERi = Quarterly weighted average, for month “i” (lb/MMBtu 

(lb/TBtu for Hg) heat input)(as calculated by (f)(1) or (2)).

(g) You must develop, and submit to the applicable regulatory 

authority for review and approval upon request, an 

implementation plan for emission averaging according to the 

following procedures and requirements in paragraphs (g)(1) 

through (4) of this section.

(1) You must submit the implementation plan no later than 180 

days before the date that the facility intends to demonstrate 

compliance using the emission averaging option.

(2) You must include the information contained in paragraphs 

(g)(2)(i) through (vii) of this section in your implementation 

plan for all emission sources included in an emissions average:

(i) The identification of all existing EGUs in the averaging 

group, including for each either the applicable HAP emission 

level or the control technology installed as of [INSERT DATE 60 

DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL 

REGISTER] and the date on which you are requesting emission 

averaging to commence;
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(ii) The process parameter (heat input 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, the owner or operator must identify each 

EGU;

(iv) The test plan for the measurement of PM, HF, HCl, 

individual or total non-Hg HAP metals, or Hg emissions in 

accordance with the requirements in §63.10007; and

(v) A demonstration that compliance with each of the applicable 

emission limit(s) will be achieved under representative 

operating conditions.

(3) The regulatory authority shall review and approve or 

disapprove the plan according to the following criteria:

(i) Whether the content of the plan includes all of the 

information specified in paragraph (g)(2) of this section; and

(ii) Whether the plan presents sufficient information to 

determine that compliance will be achieved and maintained.

(4) The applicable regulatory authority shall not approve an 

emission averaging implementation plan containing any of the 

following provisions:
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(i) Any averaging between emissions of differing pollutants or 

between differing sources; or

(ii) The inclusion of any emission source other than an existing 

unit in the same subcategory.

(h) 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 PM, HF, HCl, individual or total 

non-Hg HAP metals, or Hg emissions to demonstrate compliance 

with the limits in Table 2 to this subpart if you satisfy the 

requirements in paragraph (i) or (j) of this section.

(i) For a group of two or more existing units in the same 

subcategory, each of which vents 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.

(j) For all other groups of units subject to paragraph (h) of 

this section, the owner or operator may elect to:

(1) Conduct performance tests according to procedures specified 

in §63.10007 in the common stack if affected units from other 

subcategories vent to the common stack. The emission limits that 

the group must comply with are determined by the use of equation 
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6.

Where:

En = HAP emissions limit, lb/MMBtu (lb/TBtu for Hg), ppm, or 

ng/dscm.

ELi = Appropriate emissions limit from Table 2 to this subpart 

for unit i, in units of lb/MMBtu (lb/TBtu for Hg), ppm, or 

ng/dscm.

Hi = Heat input from unit i, MMBtu.

n = Number of units.

(2) Conduct performance tests according to procedures specified 

in §63.10007 in the common stack. If affected units from 

nonaffected units vent to the common stack, the nonaffected 

units must be shut down or vented to a different stack during 

the performance test or each affected and each nonaffected unit 

must meet the most stringent emissions limit; and

(3) Meet the applicable operating limit specified in §63.10021 

and Table 4 to this subpart for each emissions control system 

(except that, if each unit venting to the common stack has an 

applicable opacity operating limit, then a single continuous 

opacity monitoring system may be located in the common stack 

instead of in each duct to the common stack).

(k) Combination requirements. The common stack of a group of two 

or more existing EGUs in the same subcategory subject to 
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paragraph (h) of this section may be treated as a single stack 

for purposes of paragraph (b) of this section and included in an 

emissions averaging group subject to paragraph (b) 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, 

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 

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 
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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). 

When one or more affected units shares a common stack with one 

or more non-affected units, you shall either:

(i) Install the required CEMS, PM CPMS, and sorbent trap 

monitoring systems in the ducts leading to the common stack from 

each affected unit; or

(ii) 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).

(iii) 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 
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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 

configured such that emissions are controlled with a common 

control device or series of control devices that 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 

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 duct feeding into a single stack, 
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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 configured such 

that emissions are controlled with multiple parallel control 

devices or multiple series of control devices that 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 

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.
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(b) If you use an oxygen (O2) or carbon dioxide (CO2) CEMS to 

convert measured pollutant concentrations to 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, 

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, 
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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 

HCl or HF emission rate in the units of the standard, updated 

after each new boiler operating day. Each 30-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 quality-assurance (QA), the SO2 CEMS must meet 
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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 

A 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-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, i.e., do not apply bias 

adjustment factors to the part 75 SO2 data and do not use 

substitute data values from the emissions calculations.

(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-

day rolling average emission rate, calculated according to 

section 6.2 of appendix A to the subpart, is the average of all 
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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, certify, 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, certify, operate, and maintain your PM CPMS 

according to the procedures in your approved site-specific 

monitoring plan developed in accordance with §63.10005(d), the 

requirements in section (h)(1)(i) through (iii) of this section.

(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 of detecting and responding to 

particulate matter concentrations of 0.5 or fewer mg/acm.
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(2) For a new unit, complete the initial 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 180 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 §63.7535(a) through (d). 

Express the PM CPMS output as milliamps, PM concentration, or 

other raw data signal value.

(4) Calculate the arithmetic 30-day rolling average of all of 

the hourly average PM CPMS output collected during all boiler 

operating hours data (e.g., milliamps, PM concentration, raw 

data signal). 

(c) You must collect data using the PM CPMS 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, required monitoring system quality assurance or 

quality control activities (including, as applicable, 

calibration checks and required zero and span adjustments), any 

scheduled maintenance as defined in your site-specific 
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monitoring plan.

(1) 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 control 

activities conducted during monitoring system malfunctions in 

calculations and report any such periods in your annual 

deviation report;

(ii) 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;

(2) You must record and make available upon request results of 

PM CPMS system performance audits, dates and duration of periods 

when the PM CPMS is out of control to completion of the 

corrective actions necessary to return the PM CPMS to operation 

consistent with your site-specific monitoring plan.
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§63.10011 How do I demonstrate initial compliance with the 

emissions limits and work practice standards?

(a) You must demonstrate initial compliance with each emissions 

limit that applies to you by conducting performance testing.

(b) If you demonstrate initial compliance through performance 

tests, you must also establish each site-specific operating 

limit in Table 4 to this subpart that applies to your EGU(s), 

according to the requirements in §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 

operating limits.

(c)(1) If you use CEMS or sorbent trap monitoring systems to 

measure a HAP (i.e., Hg or HCl) directly, 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 emission limit in Table 1 or 2 to this 

subpart. 

(2) For a unit that uses a CEMS to measure SO2 emissions, initial 

compliance, the first 30 boiler operating day average emission 
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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

emission limit in Table 1 or 2 to this subpart. 

(e) For candidate LEE units, use the results of the performance 

testing described in §63.10005(k) 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.

(f) You must submit a Notification of Compliance Status 

containing the results of the initial compliance demonstration, 

according to §63.10030(e).

(g) You must determine the fuel whose combustion produces the 

least uncontrolled emissions, i.e., the cleanest fuel, that is 

available on site or accessible nearby for use during periods of 

startup or shutdown. 

(1) Your cleanest fuel for use during periods of startup or 

shutdown determination may take safety considerations into 

account.

(h) You must follow the startup or shutdown requirements given 

in Table 3 for each coal-fired and solid oil derived-fired EGU
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.

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. A monitoring system 

malfunction is 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. 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 out-of-control periods, 

repairs associated with monitoring system malfunctions or out-
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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 outof-control periods, repairs associated with monitoring system 

malfunctions or out-of-control 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) If you use a CEMS to measure SO2, HCl, HF, or Hg emissions, 

or using a sorbent trap monitoring system to measure Hg 

emissions, you must demonstrate continuous compliance by using 
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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.

(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, except as otherwise provided in §§63.9991(d). You 

must demonstrate continuous compliance by using all qualityassured 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, updated at the end of each new boiler operating 

day.

(d) If you use quarterly performance testing to demonstrate 

compliance with one or more applicable emissions limit 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 during one quarter 
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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. 

(e) If you must conduct periodic performance tune-ups of your 

EGU(s), as specified in paragraphs (e)(1) through (9) of this 

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 months unless your EGU employs neural net 

combustion optimization during normal operations at which you 

must perform an inspection of the burner and combustion controls 

at least once every 48 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 that affect the 

ability to optimize NOx and CO must be installed within 3 months 
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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 

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 
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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. 

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 net 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 net 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). Utilizing portable 

CO, NOx and O2 monitors for this measurement will meet the 
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requirements of this section. EGU’s employing neural net 

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 

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 the adjustments of the EGU;

(ii) A description of any corrective actions taken as a part of 

the combustion adjustment; and

(iii) The type and amount of fuel used over the 12 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).
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(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) Except where otherwise indicated, the reports required by 

this subpart must be sent to the Administrator electronically in 

an XML format prescribed by the Administrator, using EPA’s 

Emissions Collection and Monitoring Plan System (ECMPS) Client 

Tool (see §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.

§63.10022 How do I demonstrate continuous compliance under the 

emission averaging provision?

(a) Following the compliance date, the owner or operator must 
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demonstrate compliance with this subpart on a continuous basis 

by meeting the requirements of paragraphs (a)(1) through (8) 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 

determine compliance with it?

(a) During the initial performance test or any such subsequent 

performance test that demonstrates compliance with the 
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filterable PM, individual non-Hg HAP metals, or total non-Hg HAP 

metals limit 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 performance test. You must 

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 day average PM CPMS output as defined 

in paragraph 63.10022(a)(2) does not exceed the operating limit 

determined in (b) of this paragraph.

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 

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 
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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) If 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) If 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). 

For each initial compliance demonstration, you must submit the 

Notification of Compliance Status, including all performance 

test results and fuel analyses, before the close of business on 

the 60th day following the completion of the performance test 

and/or other initial compliance demonstrations according to 

§63.10(d)(2). The Notification of Compliance Status report must 

contain all the information specified in paragraphs (e)(1) 

through (6), as applicable.

(1) A description of the affected source(s) including 

identification of which subcategory the source is in, the design 
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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 

and fuel analysis; performance testing with operational limits 

(e.g., CEMS for surrogates or CPMS); CEMS; or 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 

description of the deviation, the duration of the deviation, and 
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the corrective action taken 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 three years consistent with §63.10006(o) or 

(p), 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(o) or 

(p), 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 

conduct an annual performance test of the unit.” 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 
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applies to you.

(b) Unless the EPA 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 delivered 

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 

delivered no later than July 31 or January 31, whichever date is 

the first date following the end of the semiannual reporting 

period.
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(5) For each affected source that is subject to permitting 

regulations pursuant to 40 CFR part 70 or 40 CFR part 71, 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 

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.
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(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(a)(16)(i) through (vi). 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 40 CFR part 70 or 40 CFR part 71 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 limit, operating limit, 

or work practice requirement in this subpart, submission of the 

compliance report satisfies any obligation to report the same 
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deviations in the semiannual monitoring report. However, 

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 transmit 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, 

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 
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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, 

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 data electronically into EPA’s Central Data 

Exchange by using the Electronic Reporting Tool as mentioned in 

paragraph (h) of this section. Only data collected using test 

methods compatible with ERT are subject to this requirement to 

be submitted electronically to EPA’s CDX. (2) Within 60 days 

after the reporting periods ending on March 31st, June 30th, 

September 30th, and December 31st, you must transmit 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 electronic file consistent with EPA’s 

reporting form output format. For each reporting period, the 

quarterly reports must include all of the calculated 30 day 
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rolling average values derived from the PM CPMS.

(3) Transmit the compliance reports required under paragraphs 

(c) and (d) of this section and the notification 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.(4) All reports required by this 

subpart not subject to the requirements in paragraphs (f)(1), 

(2), and (3) 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 right to require submittal of reports 

subject to paragraph (h)(1) and (2) of this section in paper 

format.

(i) If you had a malfunction during the reporting period, the 

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. The report must 

also include a description of actions taken by an owner or 
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operator during a malfunction of an affected source to minimize 

emissions in accordance with §63.10000(b), including actions 

taken to correct a malfunction.

§63.10032 What records must I keep?

(a) You must keep records according to paragraphs (a)(1) through 

(2) of this section.

(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.

(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 
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startup, shutdown, or malfunction or during another period.

(c) You must keep the records required in Table 8 to this 

subpart including records of all monitoring data and calculated 

averages for applicable operating limits such as pressure drop 

and pH 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 nonhazardous 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.
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(3) If consistent with §63.10032(b) and (c), you choose to stack 

test less frequently than annually, you must keep annual records 

that document that your emissions in the previous stack test(s) 

were less than 50 percent of the applicable emission limit for 

pollutants other than Hg from existing or new EGUs, or for Hg 

from new EGUs, less than 10 percent of the applicable emissions 

limit or less than 22 pounds of Hg per year, 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 emission 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) Records of the occurrence and duration of each startup 

and/or shutdown.

(g) Records of the occurrence and duration of each malfunction 

of operation (i.e., process equipment) or the air pollution 

control and monitoring equipment.

(h) Records of actions taken during periods of malfunction to 
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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) Records of the type and amount of fuel used during each 

startup or shutdown. 

§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). 

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 
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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; however, the U.S. EPA retains oversight of this 

subpart and can take enforcement actions, as appropriate.

(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), and approval of alternative 

analytical methods requested under §63.10008(b)(2).
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(3) Approval of major change to monitoring under §63.8(f) and as 

defined in §63.90, and approval of alternative operating 

parameters under §§63.9991(a)(2) and 63.10009(g)(2).

(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 

coal by American Society of Testing and Materials (ASTM) Method 

D388-77, 90, 91, 95, 98a, or 99 (incorporated by reference, see 

40 CFR 63.14(b)(39)).

Bituminous coal means coal that is classified as bituminous 

according to ASTM Method D388-77, 90, 91, 95, 98a, or 99 

(Reapproved 2004)1 (incorporated by reference, see 40 CFR 

63.14(b)(39)).

Boiler operating day means a 24-hour period between midnight and 
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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.

Coal means all solid fuels classifiable as anthracite, 

bituminous, sub-bituminous, or lignite by ASTM Method D388–9911

(incorporated by reference, see 40 CFR 63.14(b)(39)), 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), solventrefined coal, coal-oil mixtures, and coal-water mixtures, are 

considered “coal” for the purposes of this subpart.

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 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.
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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 

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.
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(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 

is located in the continental United States.

Deviation. (1) 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.
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(2) 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 D396–02a (incorporated by reference, see 

§63.14(b)(40)).

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 

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 
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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 utility steam generating unit (EGU) means 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.

Emission limitation means any emissions limit, work practice 

standard, or operating limit.

Equivalent means the following only as this term is used in 

Table 6 to subpart UUUUU:

(1) An equivalent sample collection procedure means a published 

voluntary consensus standard or practice (VCS) or EPA method 

that includes collection of a minimum of three composite fuel 

samples, with each composite consisting of a minimum of three 

increments collected at approximately equal intervals over the 

test period.

(2) An equivalent sample compositing procedure means a published 

VCS or EPA method to systematically mix and obtain a 
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representative subsample (part) of the composite sample.

(3) An equivalent sample preparation procedure means a published 

VCS or EPA method that: Clearly states that the standard, 

practice or method is appropriate for the pollutant and the fuel 

matrix; or is cited as an appropriate sample preparation 

standard, practice or method for the pollutant in the chosen VCS 

or EPA determinative or analytical method.

(4) An equivalent procedure for determining heat content means a 

published VCS or EPA method to obtain gross calorific (or higher 

heating) value.

(5) An equivalent procedure for determining fuel moisture 

content means a published VCS or EPA method to obtain moisture 

content. If the sample analysis plan calls for determining 

metals (especially the Hg, selenium, or arsenic) using an 

aliquot of the dried sample, then the drying temperature must be 

modified to prevent vaporizing these metals. On the other hand, 

if metals analysis is done on an “as received” basis, a separate 

aliquot can be dried to determine moisture content and the 

metals concentration mathematically adjusted to a dry basis.

(6) An equivalent pollutant (Hg) determinative or analytical 

procedure means a published VCS or EPA method that clearly 

states that the standard, practice, or method is appropriate for 

the pollutant and the fuel matrix and has a published detection 
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limit equal or lower than the methods listed in Table 6 to 

subpart UUUUU for the same purpose.

Federally enforceable means all limitations and conditions that 

are enforceable by the EPA 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 

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 their operating 

permits and have the appropriate fuel handling facilities onsite 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 
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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.

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, 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 

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 forward 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 
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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, 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 

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 
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calendar year in a combined-cycle gas turbine. No 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 D388-77, 90, 91, 95, 98a, or 99 

(Reapproved 2004)1 (incorporated by reference, see 

§63.14(a)(39)).

Limited-use liquid oil-fired subcategory means an EGU with an 

annual oil-fired capacity factor of less than 5 percent.

Liquid fuel includes, but is not limited to, distillate oil and 

residual oil.

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, 
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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.

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 
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(Pb), Manganese (Mn), Nickel (Ni), and Selenium (Se).

Oil means crude oil or petroleum or a fuel derived from crude 

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 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 D396–02a (incorporated by 

reference, see §63.14(b)(40)).

Responsible official means responsible official as defined in 40 
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CFR 70.2.

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 

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 
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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 D388-77, 90, 

91, 95, 98a, or 99 (Reapproved 2004)1 (incorporated by 

reference, see §60.14(a)(39)).

Unit designed for coal > 8,300 Btu/lb subcategory means any 

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 means any coal-fired 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 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 
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more voluntary consensus bodies. 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 

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 their rule. When this occurs, EPA has 

done searches and reviews for VCS equivalent to these non-EPA 

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.
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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 

volume or test 

run duration) 

with the test 

methods in 

Table 5...

1. Coal-fired 

unit designed 

for coal >

8,300 Btu/lb.

 

 

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

2.0E-5 lb/MWh 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)

2.0E-4 lb/GWh

8.0E-4 lb/GWh

6.0E-5 lb/GWh

4.0E-4 lb/GWh

7.0E-3 lb/GWh

8.0E-4 lb/GWh

Collect a 

minimum of 4 

dscm per run

 

1 Gross electric output
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Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

3.0E-3 lb/GWh

4.0E-3 lb/GWh

4.0E-3 lb/GWh 

3.0E-4 lb/GWh

b. Hydrogen 

chloride (HCl)

4.0E-1 lb/GWh For Method 

26A, collect a 

minimum of 2 

dscm per run. 

For ASTM 

D6348-03 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR

Sulfur dioxide 

(SO2)

2

4.0E-1 lb/MWh SO2 CEMS

c. Mercury (Hg) 2.0E-4 lb/GWh Hg CEMS or 

Sorbent trap 

monitoring 

system

2. Low Btu, 

virgin coal

 

 

a. Filterable 

particulate 

matter (PM)

7.0E-3 lb/MWh3 Collect a 

minimum of 4 

dscm per run

OR OR

Total non-Hg HAP 

metals

2.0E-5 lb/MWh 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)

2.0E-4 lb/GWh

8.0E-4 lb/GWh

6.0E-5 lb/GWh

4.0E-4 lb/GWh

7.0E-3 lb/GWh

8.0E-4 lb/GWh

3.0E-3 lb/GWh

Collect a 

minimum of 4 

dscm per run

 

2 The alternate sulfur dioxide limit may not be used if your EGU 

does not have some form of flue gas desulfurization system 

installed.

3 Gross electric output
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Manganese (Mn)

Nickel (Ni)

Selenium (Se)

4.0E-3 lb/GWh

4.0E-3 lb/GWh 

3.0E-4 lb/GWh

b. Hydrogen 

chloride (HCl)

4.0E-1 lb/GWh For Method 

26A, collect a

minimum of 2 

dscm per run. 

For ASTM 

D6348-03 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR

Sulfur dioxide 

(SO2)

4

4.0E-1 lb/MWh SO2 CEMS

c. Mercury (Hg) 4.0E-2 lb/GWh Hg CEMS or 

Sorbent trap 

monitoring 

system

3. IGCC unit

 

 

a. Filterable 

particulate 

matter (PM)

7.0E-2 lb/MWh 5

9.0E-2 lb/MWh 6

Collect a 

minimum of 1 

dscm per run

OR OR

Total non-Hg HAP 

metals

3.0E-4 lb/MWh 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)

1.0E-2 lb/GWh

8.0E-3 lb/GWh

9.0E-5 lb/GWh

1.0E-3 lb/GWh

3.0E-2 lb/GWh

3.0E-3 lb/GWh

6.0E-3 lb/GWh

Collect a 

minimum of 4 

dscm per run

 

4 The alternate sulfur dioxide limit may not be used if your EGU 

does not have some form of flue gas desulfurization system 

installed.

5 Duct burners on syngas; gross electric output

6 Duct burners on natural gas; gross electric output
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Manganese (Mn)

Nickel (Ni)

Selenium (Se)

2.0E-2 lb/GWh

2.0E-2 lb/GWh 

3.0E-1 lb/GWh

b. Hydrogen 

chloride (HCl)

3.0E-1 lb/GWh For Method 

26A, collect a 

minimum of 3 

dscm per run. 

For ASTM 

D6348-03 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR

Sulfur dioxide 

(SO2)

7

4.0E-1 lb/MWh SO2 CEMS 

c. Mercury (Hg) 3.0E-3 lb/GWh Hg CEMS or 

Sorbent trap 

monitoring 

system

4. Liquid 

oil-fired 

unit -

continental

 

 

a. Filterable 

particulate 

matter (PM)

7.0E-2 lb/MWh8 Collect a 

minimum of 1 

dscm per run

OR OR

Total HAP metals 4.0E-4 lb/MWh 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)

2.0E-3 lb/GWh

2.0E-3 lb/GWh

7.0E-4 lb/GWh

4.0E-4 lb/GWh

2.0E-2 lb/GWh

6.0E-3 lb/GWh

6.0E-3 lb/GWh

3.0E-2 lb/GWh

Collect a 

minimum of 4 

dscm per run

 

7 The alternate sulfur dioxide limit may not be used if your EGU 

does not have some form of flue gas desulfurization system 

installed.

8 Gross electric output
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Nickel (Ni)

Selenium (Se)

4.0E-2 lb/GWh

4.0E-3 lb/GWh

Mercury (Hg) 1.0E-5 lb/GWh For Method 30B 

sample volume 

determination 

(8.2.4), the 

estimated Hg 

concentration 

should 

nominally be < 

1⁄2 the standard

b. Hydrogen 

chloride (HCl)

5.0E-4 lb/MWh For Method 

26A, collect a 

minimum of 2 

dscm per run. 

For ASTM 

D6348-03 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 2 

dscm per run. 

For ASTM 

D6348-03 or 

Method 320, 

sample for a 

minimum of 1 

hour.

5. Liquid 

oil-fired 

unit – noncontinental

a. Filterable 

particulate 

matter (PM)

2.0E-1 lb/MWh9 Collect a 

minimum of 1 

dscm per run

OR OR

Total HAP metals 7.0E-3 lb/MWh Collect a 

minimum of 4 

dscm per run

OR OR

Individual HAP Collect a 

 

9 Gross electric output
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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

7.0E-2 lb/GWh

3.0E-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

7.5E0 lb/GWh

2.0E-2 lb/GWh

minimum of 4 

dscm per run

Mercury (Hg) 1.0E-4 lb/GWh For Method 30B 

sample volume 

determination 

(8.2.4), the 

estimated Hg 

concentration 

should 

nominally be < 

1⁄2 the standard

b. Hydrogen 

chloride (HCl)

5.0E-4 lb/MWh For Method 

26A, collect a 

minimum of 2 

dscm per run. 

For ASTM 

D6348-03 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 2 

dscm per run. 

For ASTM 

D6348-03 or 

Method 320, 

sample for a 

minimum of 1 

hour.

6. Solid oilderived fuela. Filterable 

particulate 

2.0E-2 lb/MWh10 Collect a 

minimum of 1 

 

10 Gross electric output
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fired unit

 

 

matter (PM) dscm per run

OR OR

Total non-Hg HAP 

metals

6.0E-4 lb/MWh 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)

9.0E-4 lb/GWh

2.0E-3 lb/GWh

8.0E-5 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

7.0E-3 lb/GWh

9.0E-4 lb/GWh

Collect a 

minimum of 4 

dscm per run

b. Hydrogen 

chloride (HCl)

3.0E-4 lb/MWh For Method

26A, collect a 

minimum of 3 

dscm per run. 

For ASTM 

D6348-03 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR

Sulfur dioxide 

(SO2)

11

4.0E-1 lb/MWh SO2 CEMS 

c. Mercury (Hg) 2.0E-3 lb/GWh Hg CEMS or 

Sorbent trap 

monitoring 

system 

Table 2 to Subpart UUUUU of Part 63 — Emission Limits for 

Existing EGUs

 

11 The alternate sulfur dioxide limit may not be used if your EGU 

does not have some form of flue gas desulfurization system 

installed.
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As stated in §63.9991, you must comply with the following 

applicable emission limits:12

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) 

with the 

test 

methods in 

Table 5...

1. Coal-fired 

unit designed 

for coal >

8,300 Btu/lb.

 

 

a. Filterable 

particulate 

matter (PM)

3.0E-2 lb/MMBtu or 

3.0E-1 lb/MWh13

Collect a 

minimum of 

1 dscm per 

run

OR OR

Total non-Hg 

HAP metals

5.0E-5 lb/MMBtu

5.0E-4 lb/MWh

Collect a 

minimum of 

4 dscm per 

run

OR OR

Individual HAP 

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

6.0E-1 lb/TBtu or

6.0E-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 

4 dscm per 

run

 

12 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.

13 Gross electric output
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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

3.1E0 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 60 

liters per 

run. For 

ASTM D6348-

03 or 

Method 320, 

sample for 

a minimum 

of 1 hour.

OR

Sulfur dioxide 

(SO2)

14

2.0E-1 lb per MMBtu 

or

1.5E0 lb per MWh

SO2 CEMS 

c. Mercury (Hg) 1.2E0 lb/TBtu or

2.0E-2 lb/GWh

LEE Testing 

for 30 days 

with 10 

days 

maximum per 

Method 30B 

run or Hg 

CEMS or 

 

14 The alternate sulfur dioxide limit may not be used if your EGU 

does not have some form of flue gas desulfurization system 

installed.
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Sorbent 

trap 

monitoring 

system

2. Low Btu, 

virgin coal

 

 

a. Filterable 

particulate 

matter (PM)

3.0E-2 lb/MMBtu or 

3.0E-1 lb/MWh15

Collect a 

minimum of 

1 dscm per 

run

OR OR

Total non-Hg 

HAP metals

5.0E-5 lb/MMBtu or

5.0E-4 lb/MWh

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)

6.0E-1 lb/TBtu or

6.0E-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

4.1E0 lb/TBtu or

5.0E-2 lb/GWh

3.1E0 lb/TBtu or

4.0E-2 lb/GWh

5.0E0 lb/TBtu or

6.0E-2 lb/GWh

Collect a 

minimum of 

4 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; 

 

15 Gross electric output
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 875 of 984

for Method 

26, collect 

a minimum 

of 120 

liters per 

run. For 

ASTM D6348-

03 or 

Method 320, 

sample for 

a minimum 

of 1 hour.

OR

Sulfur dioxide 

(SO2)

16

2.0E-1 lb/MMBtu or

1.5E0 lb per MWh

SO2 CEMS 

c. Mercury (Hg) 3.3E0 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

3. IGCC unit

 

 

a. Filterable 

particulate 

matter (PM)

4.0E-2 lb/MMBtu or

2.0E-2 lb/MWh17

Collect a 

minimum of 

1 dscm per 

run

OR OR

Total non-Hg 

HAP metals

5.0E-5 lb/MMBtu or

3.0E-3 lb/MWh

Collect a 

minimum of 

4 dscm per 

run

OR OR

Individual HAP Collect a 

 

16 The alternate sulfur dioxide limit may not be used if your EGU 

does not have some form of flue gas desulfurization system 

installed.

17 Gross electric output
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 876 of 984

metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

4.0E-1 lb/TBtu or

4.0E-3 lb/GWh

1.2E0 lb/TBtu or

2.0E-2 lb/GWh

3.0E-2 lb/TBtu or

3.0E-4 lb/GWh

2.0E-1 lb/TBtu or

2.0E-3 lb/GWh

2.9E0 lb/TBtu or

2.0E-2 lb/GWh

1.2E0 lb/TBtu or

4.0E-3 lb/GWh

2.0E-4 lb/MMBtu or

3.0E-3 lb/MWh

 2.5E0 lb/TBtu or

2.0E-2 lb/GWh

4.2E0 lb/TBtu or

5.0E-2 lb/GWh

2.2E1 lb/TBtu or

2.0E-1 lb/GWh

minimum of 

4 dscm per 

run

b. Hydrogen 

chloride (HCl)

5.0E-4 lb/MMBtu or

3.0E-3 lb/MWh

For Method 

26A, 

collect a 

minimum of 

2 dscm per

Run. For 

ASTM D6348-

03 or 

Method 320, 

sample for 

a minimum 

of 1 hour.

c. Mercury (Hg) 2.2E0 lb/TBtu or

2.0E-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 877 of 984

4. Liquid oilfired unit –

continental

 

a. Filterable 

particulate 

matter (PM)

3.0E-2 lb/MMBtu or

2.0E-1 lb/MWh18

Collect a 

minimum of 

1 dscm per 

run

OR OR

Total HAP 

metals

8.0E-5 lb/MMBtu or 

2.0E-04 lb/MWh

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)

3.0E-1 lb/TBtu or

3.0E-3 lb/GWh

5.0E-1 lb/TBtu or

7.0E-3 lb/GWh

6.0E-2 lb/TBtu or

7.0E-4 lb/GWh

2.0E-1 lb/TBtu or

2.0E-3 lb/GWh

1.8E0 lb/TBtu or

3.0E-2 lb/GWh

1.0E0 lb/TBtu or

3.0E-2 lb/GWh

2.3E0 lb/TBtu or

4.E-20 lb/GWh

2.9E0 lb/TBtu or

7.0E-2 lb/GWh

5.6E0 lb/TBtu or

7.0E-2 lb/GWh

1.2E0 lb/TBtu or

2.E-20 lb/GWh

Collect a 

minimum of 

4 dscm per 

run

Mercury (Hg) 2.0E-1 lb/TBtu or

8.0E-4 lb/GWh

For Method 

30B sample 

volume 

determinati

on (8.2.4), 

the 

estimated 

Hg 

concentrati

on should 

 

18 Gross electric output
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 878 of 984

nominally 

be < 1⁄2 the 

standard

b. Hydrogen 

chloride (HCl)

3.0E-4 lb/MMBtu or

4.0E-3 lb/MWh

For Method 

26A, 

collect a 

minimum of 

3 dscm per

run. For 

ASTM D6348-

03 or 

Method 320, 

sample for 

a minimum 

of 1 hour.

c. Hydrogen 

fluoride (HF)

2.0E-4 lb/MMBtu or

2.0E-3 lb/MWh

For Method 

26A, 

collect a 

minimum of 

3 dscm per

Run. For 

ASTM D6348-

03 or 

Method 320, 

sample for 

a minimum 

of 1 hour.

5. Liquid oilfired unit –

non-continental

 

a. Filterable 

particulate 

matter (PM)

8.0E-2 lb/MMBtu or

8.0E-1 lb/MWh19

Collect a 

minimum of 

1 dscm per 

run

OR OR

Total HAP 

metals

2.0E-3 lb/MMBtu or 

2.0E-2 lb/MWh

Collect a 

minimum of 

4 dscm per 

run

OR OR

Individual HAP 

metals:

Antimony (Sb) 1.4E0 lb/TBtu or

Collect a 

minimum of 

4 dscm per 

 

19 Gross electric output
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 879 of 984

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

2.0E-2 lb/GWh

4.0E0 lb/TBtu or

4.0E-2 lb/GWh

5.0E-1 lb/TBtu or

4.0E-3 lb/GWh

2.0E-2 lb/TBtu or

2.0E-3 lb/GWh

5.2E0 lb/TBtu or

6.0E-2 lb/GWh

5.1E1 lb/TBtu or

6.0E-1 lb/GWh

3.0E0 lb/TBtu or

3.0E-2 lb/GWh

2.0E1 lb/TBtu or

3.0E-1 lb/GWh

5.3E2 lb/TBtu or

6.2E0 lb/GWh

2.3E0 lb/TBtu or

3.0E-2 lb/GWh

run

Mercury (Hg) 5.0E-2 lb/TBtu or

5.0E-4 lb/GWh

For Method 

29 collect 

a minimum 

of 4 dscm 

per run or 

for Method 

30B sample 

volume 

determinati

on (8.2.4), 

the 

estimated 

Hg 

concentrati

on should 

nominally 

be < 1⁄2 the 

standard

b. Hydrogen 

chloride (HCl)

7.0E-4 lb/MMBtu or

7.0E-3 lb/MWh

For Method 

26A, 

collect a 

minimum of 

2 dscm per

run. For 

ASTM D6348-

03 or 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 880 of 984

Method 320, 

sample for 

a minimum 

of 2 hours.

c. Hydrogen 

fluoride (HF)

8.0E-5 lb/MMBtu or

7.0E-4 lb/MWh

For Method 

26A, 

collect a 

minimum of 

4 dscm per 

run. For 

ASTM D6348-

03 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/MWh20

Collect a 

minimum of 

1 dscm per 

run

OR OR

Total non-Hg 

HAP metals

4.0E-5 lb/MMBtu or

6.0E-2 lb/GWh

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)

9.0E-2 lb/TBtu or

8.0E-4 lb/GWh

3.0E-1 lb/TBtu or

5.0E-3 lb/GWh

5.0E-2 lb/TBtu or

5.0E-3 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

Collect a 

minimum of 

4 dscm per 

run

 

20 Gross electric output
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 881 of 984

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

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-2 lb/GWh

1.2E0 lb/TBtu

2.0E-2 lb/GWh

b. Hydrogen 

chloride (HCl)

5.0E-3 lb/MMBtu or

8.0E-2 lb/GWh

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-

03 or 

Method 320, 

sample for 

a minimum 

of 1 hour.

OR

Sulfur dioxide 

(SO2)

21

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 

 

21 The alternate sulfur dioxide limit may not be used if your EGU 

does not have some form of flue gas desulfurization system 

installed.
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 882 of 984

system

Table 3 to Subpart UUUUU of Part 63 — Work Practice Standards

As stated in §§63.9991, you must comply with the following 

applicable work practice standards:

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

1. An existing EGU Conduct a tune-up of the EGU burner 

and combustion controls at least each 

36 months, or each 48 months if neural 

net combustion optimization software 

is employed, as specified in 

§63.10021(e).

2. A new EGU Conduct a tune-up of the EGU burner 

and combustion controls at least each 

36 months, or each 48 months if neural 

net combustion optimization software 

is employed, as specified in 

§63.10021(e).

3. A coal-fired or 

solid oil derived 

fuel-fired EGU 

during cold startup 

You must operate all CMS during 

startup. For startup of a cold unit 

(i.e., starting from a state of no 

combustion in the 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 solid fuel, you must 

engage all of the applicable control 

technologies except SCR. You must 

engage the SCR once the temperature of 

that device has reached minimum SCR 

operating temperature. The startup 

period ends when you engage the 

electrical generator. You must comply 

with all applicable emissions limits 

at all times except for startup and 

shutdown periods conforming with this 

work practice. You must keep records 

during periods of startup. You must 

provide reports concerning activities 

and periods of startup, as specified 

in §63.10011(g),(h),(i), and (j) and 

§63.10021(h),(i), and(j).

4. A coal-fired or You must operate all CMS during 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 883 of 984

solid oil derived 

fuel-fired EGU 

during shutdown

shutdown. For shutdown procedures 

ending in a cold unit (i.e., ending 

with a state of no fuel combustion in 

the unit), unit shutdown begins when 

you disengage the electrical 

generator. During shutdown, you must 

operate all applicable control 

technologies while firing solid fuel. 

You may disengage applicable control 

technologies once you stop burning 

solid fuel. The end of shut down 

coincides with the end any fuel firing 

in the unit. You must comply with all 

applicable emissions limits at all 

times except for startup and shutdown 

periods conforming with this work 

practice. You must keep records during 

periods of startup. You must provide 

reports concerning activities and 

periods of startup, as specified in 

§63.10011(g),(h),(i), and (j) and 

§63.10021(h),(i), and(j).

5. An existing 

liquid oil-fired EGU 

with an annual 

capacity factor less 

than 5.0 percent

Conduct a tune-up of the EGU burner 

and combustion controls at least each 

36 months, or each 48 months if neural 

net combustion optimization software 

is employed, as specified in 

§63.10021(e).

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-day rolling average PM CPMS 

output at or below the highest 1-hour average 

measured during the most recent performance test 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 884 of 984

demonstrating compliance with the filterable PM, 

total non-mercury HAP metals, or individual nonmercury HAP metals emissions limitation.

Table 5 to Subpart UUUUU of Part 63 — Performance Stack Testing 

Requirements

As stated in §63.10007, you must comply with the following 

requirements for performance testing for existing, new or 

reconstructed affected sources:22

To conduct a 

performance test 

for the 

following 

pollutant ...

Using...

You must perform the 

following activities, as 

applicable ...

Using ...23,24

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 flow-rate of the 

stack gas.

Method 2, 2A, 2C, 

2F, 2G or 2H at 

Appendix A-1 or A2 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.

d. Measure the moisture 

content of the stack gas

Method 4 at 

Appendix A-3 to 

part 60 of this 

chapter. 

e. Measure the filterable 

PM concentration

Method 5 at 

Appendix A-3 to 

part 60 of this 

chapter.

 

22 For emissions calculations involving periods of startup or 

shutdown, use procedures in §63.10005(l).

23 All ASTM, ANSI, an ASME methods are incorporated by reference.

24 See Tables 1 and 2 for required sample volumes and/or sampling 

run times.
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 885 of 984

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 320°F ± 

25°F.

f. Convert emissions 

concentration to 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 non-Hg 

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 flow-rate of the 

stack gas.

Method 2, 2A, 2C, 

2F, 2G or 2H at 

Appendix A-1 or A2 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.

d. Measure the moisture 

content of the stack gas.

Method 4 at 

Appendix A-3 to 

part 60 of this 

chapter.

Method 29 at 

Appendix A-8 to 

part 60 of this 

chapter. For 

liquid oil-fired 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 886 of 984

e. Measure the HAP metals 

emissions concentrations 

and determine each 

individual HAP metals 

emissions concentration, as 

well as the total 

filterable HAP metals 

emissions concentration and 

total HAP metals emissions 

concentration.

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 per 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)).

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 flow-rate of the 

stack gas.

Method 2, 2A, 2C, 

2F, 2G or 2H at 

Appendix A-1 or A2 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.

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 at 

Appendix A-8 to 

part 60 of this 

chapter or Method 

320 at Appendix to 

part 63 of this 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 887 of 984

chapter and ASTM 

6348 including 

spiking procedures 

of Annex 5, if 

there are no 

entrained water 

droplets in the 

exhaust stream, 

and spike levels 

are between the 

emission standard 

and the MDC (ASTM 

D6348) or MAU, or 

Method 26A if 

there are 

entrained water 

droplets in the 

exhaust stream.

f. Convert emissions 

concentration to lb/MMBtu 

or lb per 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)).

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 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 888 of 984

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 A8 for Method 30B 

point selection.

b. Determine velocity and 

volumetric flow-rate of the 

stack gas.

Method 2, 2A, 2C, 

2F, 2G or 2H at 

Appendix A-1 or A2 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.

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 

D6784-02 (2008), 

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 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)).
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 889 of 984

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

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 A8 for Method 30B 

point selection.

b. Determine velocity and 

volumetric flow-rate of the 

stack gas.

Method 2, 2A, 2C, 

2F, 2G, or 2H at 

Appendix A-1 or A2 to part 60 of 

this chapter or 

flow monitoring 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

Page 890 of 984

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, or 

diluent gas 

monitoring systems 

certified according 

to part 75 of this 

chapter.

d. Measure the moisture 

content of the stack gas.

Method 4 at 

Appendix A-3 to 

part 60 of this 

chapter, or 

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 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)).
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g. Convert average 

lb/TBtu or lb/GWh Hg 

emission rate to lb per 

year, if you are attempting 

to meet the 22.0 lb/year 

threshold.

Potential maximum 

annual heat input 

in TBtu or 

potential 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 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)).

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-Hg HAP 

metals, 

individual 

non-Hg HAP 

metals, 

Install, 

certify, 

maintain, and 

operate a PM 

CPMS monitoring 

emissions 

discharged to 

the atmosphere 

Establish 

a sitespecific 

operating 

limit in 

units PM 

CPMS 

output 

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 
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Page 892 of 984

total HAP 

metals, 

individual 

HAP metals

 

 

 

according to 

§63.10010(g)(1)

signal 

(e.g., 

milliamps, 

mg/acm, or 

other raw 

signal)

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 

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 SO2, HCl, 

HF, or Hg emissions, or using 

a sorbent trap monitoring 

system to measure Hg

Calculating the 30 operating day 

rolling arithmetic average 

emissions rate in units of the 

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.
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2. PM CPMS to measure 

compliance with a parametric 

operating limit 

 

Calculating the arithmetic 30 

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.

3. Monthly performance testing 

for coal-fired and solid oil 

derived fired units or 

Quarterly performance testing 

for liquid oil-fired units to 

measure compliance with one or 

more applicable emissions 

limit in Table 1 or 2

Calculating the results of the 

testing in units of the 

applicable emissions standard.

4. Conducting periodic 

performance tune-ups of your 

EGU(s) 

 

Conducting periodic performance 

tune-ups of your EGU(s), as 

specified in §63.10021(e).

5. Work practice standards for 

coal-fired or solid oil 

derived fuel-fired EGUs during 

cold startup 

Operating in accordance with 

§63.10000(a).

6. Workpractice standards for 

coal-fired or solid oil 

derived fuel-fired EGUs during 

shutdown

Operating in accordance with 

§63.10000(a).

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(n) 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 
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(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 

out-of-control as 

specified in §63.8(c)(7), 

a statement that there 

were no periods during 

which the CMSs were outof-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 system, and 

operating parameter 

monitoring systems, were 

out-of-control, as 

specified in §63.8(c)(7), 
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the report must contain 

the information in 

§63.10031(e).

2. An immediate 

startup, shutdown, 

and malfunction 

report if you had a 

startup, shutdown, 

or malfunction 

during the reporting 

period that is not 

consistent with your 

startup, shutdown, 

and malfunction 

plan, and the source 

exceeds any 

applicable emission 

limitation in the 

emission standard 

a. Actions taken for the 

event; and

i. By fax or 

telephone within 2 

working days after 

starting actions 

inconsistent with 

the plan; and

b. The information in 

§63.10(d)(5)(ii)

ii. By letter 

within 7 working 

days after the end 

of the event 

unless you have 

made alternative 

arrangements with 

the permitting 

authority.

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

63.8(c)(1)(i) General duty to

minimize emissions 

and CMS operation

§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 63.10031(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 an 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 
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quality assurance requirements in section 5 of this appendix.

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 
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concentration values when the system is able to provide qualityassured 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. 
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A non-redundant backup monitoring system must be represented as 

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 
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apply:

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 
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temporary like-kind replacement analyzer for more than 720 hours 

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 
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before intermittent analysis and reporting.

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 
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meets the performance requirements of the “EPA Traceability 

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.
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3.1.10 Mid-Level Gas means calibration gas with a concentration 

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, 
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to respond to a known step change in gas concentration. For this 

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 
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hours (as defined in this section).

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.

 

Probe

Mercury 

Analyzer

Sample 

Conversion & 

Conditioning

Calibration 

Module 

Dilution 

Air
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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

 

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, 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 

may 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 the next 

highest integer. Alternatively, you may round off the span value 

to the next highest multiple of 10 μg/scm.

3.2.1.4.3 Full-Scale Range. The full-scale range of the Hg 

analyzer output must include 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), (h), or (j).

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 

certification 

test.....

The main 

performance 

specification1is.....

The alternate performance 

specification1is.....

And the conditions of 

the alternate 

specification are.....

7-day 

calibration 

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

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/m3, for 2 minutes. 
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** 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 

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 
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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 (sometimes referred to as the 

Ontario Hydro Method) 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 
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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 

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 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 
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data for bias is not required.

4.1.2 Sorbent Trap Monitoring Systems. For the initial 

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:

 For stack Hg concentrations >1 μg/dscm, ≤10% of section 1 

Hg mass;

 For stack Hg concentrations ≤1 μg/dscm and >0.5 μg/dscm, ≤ 

20% of section 1 Hg mass;

 For stack Hg concentrations ≤0.5 μg/dscm and >0.1 μg/dscm, 

≤ 50% of section 1 Hg mass; and

 For stack Hg concentrations ≤ 0.1μg/dscm, no breakthrough 

criterion assuming all other QA/QC specifications are met.

The type of sorbent material used by the traps during the RATA 

must be the same as for daily operation of the 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.

4.1.2.3 Calculation of RATA Results. Calculate the relative 
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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.

4.1.2.4 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.

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 
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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 

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 
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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 

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.
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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.

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 
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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 

to complete 7-day calibration error tests, linearity checks, 

cycle time tests, and RATAs shall be as specified in 

§75.20(b)(3)(iv) 

Table A-2: On-Going QA Test Requirements for Hg CEMS
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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 high- level 

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

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 .

of this chapter. Required system integrity checks must be 

completed within 168 unit or stack operating hours after the 

probationary calibration error test.

5.1.6 Adjustment of Span. If the Hg concentration readings 

exceed the span value for a significant percentage of the unit 

operating hours in a calendar quarter, make any necessary 

adjustments to the MPC and span value. A diagnostic linearity 

check is required within 168 unit or stack operating hours after 

changing the span value.

5.2 Sorbent Trap Monitoring Systems.
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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.

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 
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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.

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 
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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 

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 
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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 

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 
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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 

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 
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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.

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.
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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 

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 
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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 or the hourly average CO2 concentration is below 

5.0% CO2 (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, 

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)
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Where:

Mh = Hg mass emission rate for the hour (lb/hr)

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  Bws 1 (Equation A-3)

Where:

Mh = Hg mass emission rate for the hour (lb/hr)

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)

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/hr).

(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 
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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 

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.
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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.

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 
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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 

justifications.

7.1.2 Operating Parameter Records. The owner or operator shall 

record the following information for each operating hour of each 
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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;

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;
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7.1.3.3 The hourly Hg concentration, if a quality-assured value 

is obtained for the hour (μg/scm, rounded to the nearest tenth);

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;

7.1.4.3 The hourly Hg concentration, if a quality-assured value 

is obtained for the hour (μg/scm, rounded to the nearest tenth). 

Note that when a quality-assured Hg concentration value is 

obtained for a particular data collection period, that single 
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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 

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 
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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 

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.
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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 Mass Emissions Records. When compliance with a Hg 

emission limit in units of lb/GWh is required, Hg mass emissions 

must be calculated. In such cases, record the following 

information for each operating hour of affected unit or common

stack:

7.1.8.1 The date and hour;
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7.1.8.2 The calculated hourly Hg mass emissions, from Equation 

A-2 or A-3 in section 6.2.2 of this appendix (lb, rounded to 

three decimal places), if valid values of Hg concentration, 

stack gas volumetric flow rate, and (if applicable) moisture 

data are all obtained for the hour;

7.1.8.3 An identification code for the formula (either Equation 

A-2 or A-3 in section 6.2.2 of this appendix) used to calculate 

hourly Hg mass emissions from Hg concentration, flow rate and 

(if applicable) moisture data; and

7.1.8.4 A code indicating that the Hg mass emissions were not 

calculated for the hour, if valid data for Hg concentration, 

flow rate, and/or moisture (as applicable) 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 Hg Emission Rate Records. For applicable Hg emission 

limits in units of lb/TBtu or lb/GWh, record the following 

information for each affected unit or common stack:

7.1.9.1 The date and hour;

7.1.9.2 The hourly Hg emissions rate (lb/TBtu or lb/GWh, as 

applicable, rounded to three decimal places), if valid values of 

Hg concentration and all other required parameters (stack gas 
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volumetric flow rate, diluent gas concentration, electrical 

load, and moisture data, as applicable) are obtained for the 

hour;

7.1.9.3 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

7.1.9.4 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. 

7.1.10 Certification and Quality Assurance Test Records. For any 

Hg CEMS and sorbent trap monitoring systems used to provide data 

under this subpart, record the following certification and 

quality-assurance information:

7.1.10.1 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 
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required 7-day calibration error tests and daily calibration 

error tests of the Hg CEMS;

7.1.10.2 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;

7.1.10.3 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;

7.1.10.4 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;

7.1.10.5 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 

sample analyses to substantiate the reported test results, and 

records of sampling equipment calibrations; 

7.1.10.6 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 
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applicable quality control procedures described in Table 12B-1 

of Performance Specification (PS) 12B in appendix B to part 60 

of this chapter.

7.1.10.7 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 (see §63.10032(b)(3)).

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;

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 
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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 

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 submitted to 

the permitting authority.
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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 Acid Rain 

Program) 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 §63.10005(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) 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.
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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 7.1.9 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 7.1.10.1 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 

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. 
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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 §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 

pollutant concentrations to units of the applicable emissions 

limit.

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 for extractive Fourier Transform 
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Infrared Spectroscopy (FTIR) continuous emissions monitoring 

systems in appendix B to part 60 of this chapter 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 3.1.1.1 and 3.1.1.2 below. 

3.1.1.1 The audit sample does not have to be obtained from the 

Administrator; however, the audit gas must be (1) independent of 

any calibration gas used for the daily calibration error 

assessment and (2) traceable to National Institute of Standards 

and Technology (NIST) or VSL Dutch Metrology Institute (VSL) 

reference materials through an unbroken chain of comparisons or, 

if those are not available, certified to a specified uncertainty 

by a 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 must be between 

0.85 and 1.15. You do not have to test the bias for statistical 
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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, Method 320 in 

Appendix A to part 63, or ASTM 6348-03 each applied based on the 

criteria set forth in Table 5 of this subpart. When ASTM 6348-03 

is used as the RM, the following conditions must be met: (1) the 

test plan preparation and implementation in the Annexes to ASTM 

D 6348-03, Sections A1 through A8 are mandatory; (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) 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: Reported Result = 

(Measured Concentration in the Stack x 100 / % R. 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 is less 

than 1.0 ppm, the RA results are acceptable if the absolute 
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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.

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.
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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 

of this appendix. 

5.1.1 On a daily basis, you must perform either a calibration 

transfer standard test or a system calibration test as described 

in Performance Specification 15 sections 10.1 or 10.3, 

respectively, to assess calibration error. The measured 

concentration of the calibration standard or calibration 

transfer standard 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 conduct 

a relative accuracy test audit as described in section 3.1.2 of 

this appendix instead of a quarterly gas audit. . 5.1.3 

Annually, in place of the quarterly gas audit, you must perform 

a relative accuracy test audit or RATA as described in section 
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3.1.2 of this appendix. Perform the RATA of the HCl or HF CEMS 

at normal load. For the purposes of this appendix, “annually” 

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 test of the 

HCl or HF CEMS is 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 

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.
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5.3.2 Daily Calibration Error Assessment. For the purposes of 

this appendix, the assessment of daily calibration error for all 

monitoring systems shall be done according to section 2.1 of 

appendix B to part 75 of this chapter, with the following 

exceptions. For HCl or HF CEMS subject to Performance 

Specification 15 of appendix B, the allowable daily system 

calibration error (or daily calibration transfer standard error) 

assessment shall be conducted according to section 5.1.1 of this 

appendix and the system shall be considered out-of-control when 

the calibration error is greater than ± 2 times the performance 

specification in section 5.1.1 of this appendix. 

5.3.3 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.

5.3.3.1 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.
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5.3.3.2 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 to circumstances beyond the control of the owner or 

operator, a 720 unit or stack operating hour grace period is 

available in which to perform the gas audit or RATA. 

5.3.3.3 If a required QA test is performed during a grace 

period, the deadline for the next test shall be determined as 

follows:

5.3.3.3.1 For a linearity check or RATA of the monitoring 

systems described in section 5.2 of this appendix, determine the 

deadline for the next linearity check 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.

5.3.3.3.2 For the gas audit of a HCl or HF CEMS, the next gas 

audit is due within two calendar months following the month in 

which the grace period test is performed.

5.3.3.3.3 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 test was originally required to be 

performed.

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 
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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 7-

day calibration tests, gas audits, and RATAs shall be as 

specified in §75.20(b)(3)(iv) of this chapter, with the gas 

audits following the provisions for linearity checks.

6. Missing Data Requirements. For the purposes of this 

appendix, the owner or operator of an affected unit is not 

required to substitute for missing data from HCl or HF CEMS. 

Any process operating hour for which quality-assured HCl or 

HFconcentration 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 

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) 
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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 

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 
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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 

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 
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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 or HF concentration value (ppm) by 

9.43 x 10-8 to convert it to lb/scf, for use in the applicable 

Method 19 equation.

9.3.2 For electrical output-based emission rates, first 

calculate the HCl or HF mass emissions (lb), 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 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 19-19 in EPA Method 19 to calculate the 

required 30 operating day rolling average HCl or HF emission 

rates. The term Ehj in Equation 19-19 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, 
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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 

10.1.9 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.

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 
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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 types of systems under §75.53 (g) of this chapter. The 

electronic monitoring plan shall be evaluated and submitted 

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 

applicable).

10.1.1.2.2 Hard Copy. Keep records of the following: 

schematics and/or blueprints showing the location of the 
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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

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 
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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 the nearest tenth). 

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 

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 
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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 

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 
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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 or HF Mass Emissions Records. To assess compliance 

with an HCl or HF emission limit in units of lb/MWh or lb/GWh,

pollutant mass emissions (lb) must be calculated. In such 

cases, record the following hourly information for each 

operating hour of the affected source:

10.1.7.1 The date and hour;

10.1.7.2 The calculated hourly HCl or HF mass emissions (lb), 

rounded to three significant figures, for each hour in which 

valid values of pollutant concentration, stack gas volumetric 

flow rate, and (if applicable) moisture data are all obtained 

for the hour;
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10.1.7.3 An identification code for the formula used to 

calculate the hourly HCl or HF mass emissions from HCl or HF 

concentration, flow rate and (if applicable) moisture data; and

10.1.7.4 A code indicating that the HCl or HF mass emissions 

were not calculated for the hour, if valid data for HCl or HF 

concentration, flow rate, and/or moisture (as applicable) 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 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:

10.1.8.1 The date and hour;

10.1.8.2 The hourly HCl and/or HF emissions rate (lb/MMBtu, 

lb/MWh, or lb/GWh, as applicable, rounded to three significant 

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;

10.1.8.3 An identification code for the formula used to derive 
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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

10.1.8.4 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. 

10.1.9 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:

10.1.9.1 HCl and HF CEMS. 

10.1.9.1.1 For all required daily calibration error tests (or 

daily calibration transfer standard error tests) of the HCl or 

HF CEMS, record the test dates and times, reference values, 

monitor responses, and calculated calibration error values;

10.1.9.1.2 For each gas audit of a HCl or HF CEMS, record the 

date and time of each audit gas spike, the audit gas reference 
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values and uncertainties. Keep records of all calculations and 

data analyses required under sections 9.1 and 12.0 of PS 15, and 

the results of those calculations and analyses. 

10.1.9.1.3 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 all 

calculations, graphs, and data analyses required under sections 

11.1.1.4 and 12.0 of PS 15, and the results of those 

calculations and analyses. 

10.1.9.2 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(a) of this chapter.

11. Reporting Requirements

11.1 General Reporting Provisions. The owner or operator shall 

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;
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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, 

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.
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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 submitted to 

the permitting authority.

11.4 Certification, Recertification, and Quality-Assurance Test 

Reporting Requirements. Except for daily QA tests (i.e., 

calibration error tests 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 required monitoring systems 

electronically, either prior to or concurrent with the relevant 

quarterly electronic emissions report. 

11.4.1 For daily calibration error (or calibration transfer 

standard error tests), report the information in §75.59(a)(1) of 

this chapter, excluding paragraphs (a)(1)(ix) and (a)(1)(xi). 

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 CEMS span and span scale;
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11.4.2.6 Audit (spike) gas concentration value and 

documentation of certified value; 

11.4.2.7 Measured value of undiluted audit (spike) gas, 

including date and time of injection and point in monitoring 

system that gas was injected;

11.4.2.8 Calculated dilution ratio for audit (spike) gas;

11.4.2.9 Date and time for each audit gas spike;

11.4.2.10 Units of measure;

11.4.2.11 The measured values for each spiked gas and unspiked 

gas sample, in appropriate units of measure;

11.4.2.12 Means of the measured spiked and unspiked sample 

concentrations and expected value of the spiked concentration as 

specified in section 12.1 of Performance Specification 15 in 

appendix B to part 60 of this chapter;

11.4.2.13 Bias at the spike level as calculated using equation 

3 in section 12.1 of Performance Specification 15 in appendix B 

to part 60 of this chapter;

11.4.2.14 The differences for each pair of spiked and each pair 

of unspiked gas measurements;

11.4.2.15 Standard deviation of the spiked pairs of 

measurements and standard deviation of the unspiked pairs of 

measurements, as specified in section 12.0 of Performance 

Specification 15 in appendix B to part 60 of this chapter; and
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11.4.2.16 Relative standard deviations for the spiked and 

unspiked measurements, respectively, calculated t-statistic, and 

result of the statistical significance of the bias test as 

specified in section 12.0 of Performance Specification 15 in 

appendix B to part 60 of this chapter

11.4.3 For each RATA of a HCl or HF CEMS, report:

11.4.3.1 Facility ID information;

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; 
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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 test results, as specified in 

Equation 2-6 of Performance Specification 2 in appendix B to 

part 60 of this chapter.

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 No later than the end of the 180 day compliance 

demonstration period 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 
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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:

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 10.1.8 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 calibration error (or 

calibration transfer standard error tests) of the HCl or HF 

monitor as described in section 10.1.9.1.1 of this appendix; and

11.5.3.5 If applicable, the results of all daily flow monitor 

interference checks, in accordance with section 10.1.9.2 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 
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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.