9304 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60 and 63 

[EPA–HQ–OAR–2009–0234; EPA–HQ–OAR– 

2011–0044, FRL–9611–4] 

RIN 2060–AP52; RIN 2060–AR31 

National Emission Standards for 

Hazardous Air Pollutants From Coaland Oil-Fired Electric Utility Steam 

Generating Units and Standards of 

Performance for Fossil-Fuel-Fired 

Electric Utility, Industrial-CommercialInstitutional, 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-fuelfired electric utility, industrialcommercial-institutional, and small 

industrial-commercial-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 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 

April 16, 2012. The incorporation by 

reference of certain publications listed 

in this rule is approved by the Director 

of the Federal Register as of April 16, 

2012. 

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 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; 

Email 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) 541–4003; Fax number 

(919) 541–5450; Email 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 coal- and oil-fired EGUs? 

III. Appropriate and Necessary Finding 

A. Overview 

B. Peer Review of the Hg Risk TSD 

Supporting the Appropriate and 

Necessary Finding for Coal and Oil-Fired 

EGUs and EPA Response 

C. Summary of Results of Revised Hg Risk 

TSD of Risks to Populations With High 

Levels of Self-Caught Fish Consumption 

D. Peer Review of the Approach for 

Estimating Cancer Risks Associated With 

Cr and Ni Emissions in the U.S. EGU 

Case Studies of Cancer and Non-Cancer 

Inhalation Risks for Non-Mercury Hg 

HAP and EPA Response 

E. Summary of Results of Revised U.S. 

EGU Case Studies of Cancer and NonCancer Inhalation Risks for Non-Mercury 

Hg HAP 

F. Public Comments and Responses to the 

Appropriate and Necessary Finding 

G. EPA Affirms the Finding That It Is 

Appropriate and Necessary To Regulate 

EGUs To Address Public Health and 

Environmental Hazards Associated With 

Emissions of Hg and Non-Mercury Hg 

HAP From EGUs 

IV. Denial of Delisting Petition 

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

B. Rationale for Denying UARG’s Delisting 

Petition 

C. EPA’s Technical Analyses for the 

Appropriate and Necessary Finding 

Provide Further Support for the 

Conclusion That Coal-Fired EGUs 

Should Remain a Listed Source Category 

V. Summary of the Final NESHAP 

A. What is the source category regulated by 

this final rule? 

B. What is the affected source? 

C. What are the pollutants regulated by this 

final rule? 

D. What emission limits and work practice 

standards must I meet? 

E. What are the requirements during 

periods of startup, shutdown, and 

malfunction? 

F. What are the testing and initial 

compliance requirements? 

G. What are the continuous compliance 

requirements? 

H. What are the notification, recordkeeping 

and reporting requirements? 

I. Submission of Emissions Test Results to 

the EPA 

VI. Summary of Significant Changes Since 

Proposal 

A. Applicability 

B. Subcategories 

C. Emission Limits 

D. Work Practice Standards for Organic 

HAP Emissions 

E. Requirements During Startup, 

Shutdown, and Malfunction 

F. Testing and Initial Compliance 

G. Continuous Compliance 

H. Emissions Averaging 

I. Notification, Recordkeeping and 

Reporting 

J. Technical/Editorial Corrections 

VII. Public Comments and Responses to the 

Proposed NESHAP 

A. MACT Floor Analysis 

B. Rationale for Subcategories 

C. Surrogacy 

D. Area Sources 

E. Health-Based Emission Limits 

F. Compliance Date and Reliability Issues 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9305 

G. Cost and Technology Basis Issues 

H. Testing and Monitoring 

VIII. Background Information on the NSPS 

A. What is the statutory authority for this 

final NSPS? 

B. What is the regulatory authority for the 

final rule? 

IX. Summary of the Final NSPS 

X. Summary of Significant Changes Since 

Proposal 

XI. Public Comments and Responses to the 

Proposed NSPS 

XII. Impacts of the Final Rule 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the cost impacts? 

D. What are the economic impacts? 

E. What are the benefits of this final rule? 

XIII. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory 

Planning and Review and Executive 

Order 13563, Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act as Amended 

by the Small Business Regulatory 

Enforcement Fairness Act (RFA) of 1996 

SBREFA), 5 U.S.C. 601 et seq. 

D. Unfunded Mandates Reform Act of 1995 

E. Executive Order 13132, Federalism 

F. Executive Order 13175, Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045, Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211, Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. General Information 

A. Does this action apply to me? 

The regulated categories and entities 

potentially affected by the final 

standards are shown in Table 1 of this 

preamble. 

TABLE 1—POTENTIALLY AFFECTED REGULATED CATEGORIES AND ENTITIES

Category NAICS code 1 Examples of potentially 

regulated entities 

Industry ................................................................. 221112 Fossil fuel-fired electric utility steam generating units. 

Federal government .............................................. 2 221122 Fossil fuel-fired electric utility steam generating units owned by the federal government. 

State/local/tribal government ................................ 2 221122 Fossil fuel-fired electric utility steam generating units owned by states, 

tribes, or municipalities. 

921150 Fossil fuel-fired electric utility steam generating units in Indian country. 

1 North American Industry Classification System. 

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

This table is not intended to be 

exhaustive, but rather is meant to 

provide a guide for readers regarding 

entities likely to be affected by this 

action. To determine whether you, as 

owner or operator of a facility, 

company, business, organization, etc., 

will be regulated by this action, you 

should examine the applicability 

criteria in 40 CFR 60.40, 60.40Da, or 

60.40c or in 40 CFR 63.9981. If you have 

any questions regarding the 

applicability of this action to a 

particular entity, consult either the air 

permitting authority for the entity or 

your EPA regional representative as 

listed in 40 CFR 60.4 or 40 CFR 63.13 

(General Provisions). 

B. Where can I get a copy of this 

document? 

In addition to being available in the 

dockets, an electronic copy of this 

action will also be available on the 

Worldwide Web (WWW) through the 

Technology Transfer Network (TTN). 

Following signature by the 

Administrator, a copy of the action will 

be posted on the TTN’s policy and 

guidance page for newly proposed or 

promulgated rules at the following 

address: http://www.epa.gov/ttn/oarpg/. 

The TTN provides information and 

technology exchange in various areas of 

air pollution control. 

C. Judicial Review 

Under CAA section 307(b)(1), judicial 

review of this final rule is available only 

by filing a petition for review in the U.S. 

Court of Appeals for the District of 

Columbia Circuit by April 16, 2012. 

Under CAA section 307(d)(7)(B), only 

an objection to this final rule that was 

raised with reasonable specificity 

during the period for public comment 

(including any public hearing) can be 

raised during judicial review. This 

section also provides a mechanism for 

the EPA to convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to the 

Administrator that it was impracticable 

to raise such objection within [the 

period for public comment] or if the 

grounds for such objection arose after 

the period for public comment (but 

within the time specified for judicial 

review) and if such objection is of 

central relevance to the outcome of the 

rule[.]’’ Any person seeking to make 

such a demonstration to us should 

submit a Petition for Reconsideration to 

the Office of the Administrator, 

Environmental Protection Agency, 

Room 3000, Ariel Rios Building, 1200 

Pennsylvania Ave. NW., Washington, 

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 in any civil or criminal 

proceedings brought by EPA to enforce 

these requirements. 

D. What are the costs and benefits of 

this final rule? 

Consistent with Executive Order (EO) 

13563, ‘‘Improving Regulation and 

Regulatory Review,’’ we have estimated 

the costs and benefits of the final rule. 

This rule will reduce emissions of HAP, 

including mercury (Hg), from the 

electric power industry. Installing the 

technology necessary to reduce 

emissions directly regulated by this rule 

will also reduce the emissions of 

directly emitted PM2.5 and sulfur 

dioxide (SO2), a PM2.5 precursor. The 

benefits associated with these PM and 

SO2 reductions are referred to as cobenefits, as these reductions are not the 

primary objective of this rule. 

The EPA estimates that this final rule 

will yield annual monetized benefits (in 

2007$) of between $37 to $90 billion 

using a 3 percent discount rate and $33 

to $81 billion using a 7 percent discount 

rate. The great majority of the estimates 

are attributable to co-benefits from 

reductions in PM2.5-related mortality. 

The annual social costs, approximated 


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9306 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

by the sum of the compliance costs and 

monitoring and reporting costs, are $9.6 

billion (2007$) and the annual 

quantified net benefits (the difference 

between benefits and costs) are $27 to 

$80 billion using a 3 percent discount 

rate or $24 to $71 billion using a 7 

percent discount rate. It is important to 

note that the PM2.5 co-benefits reported 

here contain uncertainty, due in part to 

the important assumption that all fine 

particles are equally potent in causing 

premature mortality and because many 

of the benefits are associated with 

reducing PM2.5 levels at the low end of 

the concentration distributions 

examined in the epidemiology studies 

from which the PM2.5-mortality 

relationships used in this analysis are 

derived. 

The benefits of this rule outweigh 

costs by between 3 to 1 or 9 to 1 

depending on the benefit estimate and 

discount rate used. The co-benefits are 

substantially attributable to the 4,200 to 

11,000 fewer PM2.5-related premature 

mortalities estimated to occur as a result 

of this rule. The EPA could not 

monetize some costs and important 

benefits, such as some Hg benefits and 

those for the HAP reduced by this final 

rule other than Hg. Upon considering 

these limitations and uncertainties, it 

remains clear that the benefits of this 

rule, referred to in short as the Mercury 

and Air Toxics Standards (MATS), are 

substantial and far outweigh the costs. 

TABLE 2—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE FINAL RULE IN 2016 

[Billions of 2007$] a

3% Discount rate 7% Discount rate 

Total Monetized Benefits b ............................................................................................. $37 to $90 .......................... $33 to $81. 

Partial Hg-related Benefits c ........................................................................................... $0.004 to $0.006 ................ $0.0005 to $0.001. 

PM2.5-related Co-benefits b ............................................................................................ $36 to $89 .......................... $33 to $80. 

Climate-related Co-Benefits d ........................................................................................ $0.36 .................................. $0.36. 

Total Social Costs e ....................................................................................................... $9.6 .................................... $9.6. 

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

Non-monetized Benefits ................................................................................................ Visibility in Class I areas. 

Other neurological effects of Hg exposure. 

Other health effects of Hg exposure. 

Health effects of ozone and direct exposure to SO2 and 

NO2. 

Ecosystem effects. 

Health effects from commercial and non-freshwater fish 

consumption. 

Health risks from exposure to non-mercury HAP. 

aAll estimates are for 2016, and are rounded to two significant figures. 

bThe total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5. The reduction in premature fatalities each year accounts for over 90 percent of total monetized benefits. Benefits in this table are nationwide and are associated with directly 

emitted PM2.5 and SO2 reductions. The estimate of social benefits also includes CO2-related benefits calculated using the social cost of carbon, 

discussed further in chapter 5 of the RIA. Mercury benefits were calculated using the baseline from proposal. The difference in emissions reductions between proposal and final does not substantially affect the Hg benefits. cBased on an analysis of health effects due to recreational freshwater fish consumption. 

dThis table shows monetized CO2 co-benefits that were calculated using the global average social cost of carbon estimate at a 3 percent discount rate. In section 5.6 of the Regulatory Impact Analysis (RIA) we also report the monetized CO2 co-benefits using discount rates of 5 percent, 2.5 percent, and 3 percent (95th percentile). eTotal social costs are approximated by the compliance costs for both coal- and oil-fired units. This includes monitoring, recordkeeping, and 

reporting costs. 

For more information on how EPA is 

addressing EO 13563, see the EO 

discussion in the Statutory and 

Executive Order Reviews section of this 

preamble. 

II. Background Information on the 

NESHAP 

On May 3, 2011, the EPA proposed 

this rule to address emissions of toxic 

air pollutants from coal and oil-fired 

electric generating units as required by 

the CAA. The proposal explained at 

length the statutory history and 

requirements leading to this rule, the 

factual and legal basis for the rule and 

its specific provisions, and the costs and 

benefits to the public health and 

environment from the proposed 

requirements. 

The EPA received over 900,000 

comments from members of the public 

on the proposed rule, substantially more 

than for any other prior regulatory 

proposal. The comments express 

concerns about the presence of Hg in the 

environment and the effect it has on 

human health, concerns about the costs 

of the rule, how challenging it may be 

for some sources to comply and 

questions about the impact it may have 

on this country’s electricity supply and 

economy. Many comments provided 

additional information and data that 

have enriched the factual record and 

enabled EPA to finalize a rule that 

fulfills the mandate of the CAA while 

providing flexibility and compliance 

options to affected sources—options 

that make the rule less costly and 

compliance more readily manageable. 

This rule establishes uniform 

emissions-control standards that sources 

can meet with proven and available 

technologies and operational processes 

in a timeframe that is achievable. They 

will put this industry, now the single 

largest source of Hg emissions in the 

United States (U.S.) with emissions of 

29 tons per year, on a path to reducing 

those emissions by approximately 90 

percent. Emissions of other toxic metals, 

such as arsenic (As) and nickel (Ni), 

dioxins and furans, acid gases 

(including hydrochloric acid (HCl) and 

SO2) will also decrease dramatically 

with the installation of pollution 

controls. And the flexibilities 

established in this rule along with other 

available tools provide a clear pathway 

to compliance without jeopardizing the 

country’s energy supply. 

This preamble explains EPA’s 

appropriate and necessary finding, the 

elements of the final rule, key changes 

the EPA is making in response to 

comments submitted on the proposed 

rule, and our responses to many of the 

comments we received. A full response 

to comments is provided in the response 

to comments document available in the 

docket for this rulemaking. 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9307 

1 ‘‘Electric utility steam generating unit’’ is 

defined, in part, as any ‘‘fossil fuel fired combustion 

unit of more than 25 megawatts that serves a 

generator that produces electricity for sale.’’ See 

CAA section 112(a)(8). 

2U.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. 

3NIEHS Study, August 1995; EPA–HQ–OAR– 

2009–3053. 

4National Research Council (NAS). 2000. 

Toxicological Effects of Methylmercury. Committee 

on the Toxicological Effects of Methylmercury, 

Board on Environmental Studies and Toxicology, 

National Research Council. 

5Mercury Study Report to Congress, December 

1997; EPA–HQ–OAR–2009–0234–3054. 

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 

to occur as a result of EGUs’ HAP 

emissions after imposition of CAA 

requirements. The EPA must report the 

results of that study to Congress, and 

regulate EGUs ‘‘if the Administrator 

finds such regulation is appropriate and 

necessary,’’ after considering the results 

of that study. Thus, CAA section 

112(n)(1)(A) governs how the 

Administrator decides whether to list 

EGUs for regulation under CAA section 

112. See New Jersey v. EPA, 517 F.3d 

574 at 582 (D.C. Cir. 2008) (‘‘Section 

112(n)(1) governs how the 

Administrator decides whether to list 

EGUs; it says nothing about delisting 

EGUs.’’). 

As directed, the EPA conducted the 

study to evaluate the remaining public 

health hazards and reported the results 

to Congress (Utility Study Report to 

Congress (Utility Study)).2 We discuss 

this study below in conjunction with 

other studies that CAA section 112(n)(1) 

requires concerning EGUs. See also 76 

FR 24982–24984 (summarizing studies). 

Once the EPA lists a source category 

pursuant to CAA section 112(c), the 

EPA must then establish technologybased emission standards under CAA 

section 112(d). For major sources, the 

EPA must establish emission standards 

that ‘‘require the maximum degree of 

reduction in emissions of the hazardous 

air pollutants subject to this section’’ 

that the EPA determines are achievable 

taking into account certain statutory 

factors. See CAA section 112(d)(2). 

These standards are referred to as 

‘‘maximum achievable control 

technology’’ or ‘‘MACT’’ standards. The 

MACT standards for existing sources 

must be at least as stringent as the 

average emission limitation achieved by 

the best performing 12 percent of 

existing sources in the category (for 

which the Administrator has emissions 

information) or the best performing 5 

sources for source categories with less 

than 30 sources. See CAA section 

112(d)(3)(A) and (B), respectively. This 

level of minimum stringency is referred 

to as the ‘‘MACT floor,’’ and the EPA 

cannot consider cost in setting the floor. 

For new sources, MACT standards must 

be at least as stringent as the control 

level achieved in practice by the best 

controlled similar source. See CAA 

section 112(d)(3). 

The EPA also must consider more 

stringent ‘‘beyond-the-floor’’ control 

options. When considering beyond-thefloor options, the EPA must consider the 

maximum degree of reduction in HAP 

emissions and take into account costs, 

energy, and non-air quality health and 

environmental impacts when doing so. 

See Cement Kiln Recycling Coal. v. EPA, 

255 F.3d 855, 857–58 (D.C. Cir. 2001). 

Alternatively, the EPA may set a 

health-based standard for HAP that have 

an established health threshold, and the 

standard must provide ‘‘an ample 

margin of safety.’’ See CAA section 

112(d)(4). As these standards could be 

less stringent than MACT standards, the 

Agency must have detailed information 

on HAP emissions from the subject 

sources and sources located near the 

subject sources before exercising its 

discretion to set such standards. 

For area sources, the EPA may issue 

standards or requirements that provide 

for the use of generally available control 

technologies or management practices 

(GACT standards) in lieu of 

promulgating MACT or health-based 

standards. See CAA section 112(d)(5). 

As noted above, CAA section 112(n) 

requires completion of various reports 

concerning EGUs. For the first report, 

the Utility Study, Congress required the 

EPA to evaluate the hazards to public 

health reasonably anticipated to occur 

as the result of HAP emissions from 

EGUs after imposition of the 

requirements of the CAA. See CAA 

section 112(n)(1)(A). The EPA was 

required to report results from this 

study to Congress by November 15, 

1993. Id. Congress also directed the EPA 

to conduct ‘‘a study of mercury 

emissions from [EGUs], municipal waste 

combustion units, and other sources, 

including area sources’’ (Mercury 

Study). See CAA section 112(n)(1)(B). 

The EPA was required to report the 

results from this study to Congress by 

November 15, 1994. Id. In conducting 

this Mercury Study, Congress directed 

the EPA to ‘‘consider the rate and mass 

of such emissions, the health and 

environmental effects of such emissions, 

technologies which are available to 

control such emissions, and the costs of 

such technologies.’’ Id. Congress 

directed the National Institute of 

Environmental Health Sciences (NIEHS) 

to conduct the last required evaluation, 

‘‘a study to determine the threshold 

level of mercury exposure below which 

adverse human health effects are not 

expected to occur’’ (NIEHS Study). See 

CAA section 112(n)(1)(C). The NIEHS 

was required to submit the results to 

Congress by November 15, 1993. Id. In 

conducting this study, NIEHS was to 

determine ‘‘a threshold for mercury 

concentrations in the tissue of fish 

which may be consumed (including 

consumption by sensitive populations) 

without adverse effects to public 

health.’’ Id. 

In addition, Congress, in conference 

report language associated with the 

EPA’s fiscal year 1999 appropriations, 

directed the EPA to fund the National 

Academy of Sciences (NAS) to perform 

an independent evaluation of the 

available data related to the health 

impacts of methylmercury (MeHg) (NAS 

Study or MeHg Study). H.R. Conf. Rep. 

No 105–769, at 281–282 (1998). 

Specifically, Congress required NAS to 

advise the EPA as to the appropriate 

reference dose (RfD) for MeHg. 65 FR 

79826. The RfD is the amount of a 

chemical which, when ingested daily 

over a lifetime, is anticipated to be 

without adverse health effects to 

humans, including sensitive 

subpopulations. In the same conference 

report, Congress indicated that the EPA 

should not make the appropriate and 

necessary regulatory determination for 

Hg emissions until the EPA had 

reviewed the results of the NAS Study. 

See H.R. Conf. Rep. No 105–769, at 281– 

282 (1998). 

As directed by Congress through 

different vehicles, the NAS Study and 

the NIEHS Study evaluated the same 

issues. The NIEHS completed the 

NIEHS Study in 1995,3 and the NAS 

completed the NAS Study in 2000.4

Because NAS completed its study 5 

years after the NIEHS Study, and 

considered additional information not 

earlier available to NIEHS, for purposes 

of this document we discuss the content 

of the NAS Study as opposed to the 

NIEHS Study. 

The EPA conducted the studies 

required by CAA section 112(n)(1) 

concerning utility HAP emissions, the 

Utility Study and the Mercury Study,5

and completed both by 1998. Prior to 

issuance of the Mercury Study, the EPA 


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9308 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

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. 

7American Nurses Association, Chesapeake Bay 

Foundation, Inc., Conservation Law Foundation, 

Environment America, Environmental Defense 

Fund, Izaak Walton League of America, Natural 

Resources Council of Maine, Natural Resources 

Defense Council, Physicians for Social 

Responsibility, Sierra Club, The Ohio 

Environmental Council, and Waterkeeper Alliance, 

Inc. (Civ. No. 1:08–cv–02198 (RMC)). 

8The 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. 

engaged in two extensive external peer 

reviews of the document. 

On December 20, 2000, the EPA 

issued a finding pursuant to CAA 

section 112(n)(1)(A) that it was 

appropriate and necessary to regulate 

coal- and oil-fired EGUs under CAA 

section 112 and added such units to the 

list of source categories subject to 

regulation under CAA section 112(d). In 

making that finding, the EPA considered 

the Utility Study, the Mercury Study, 

the NAS Study, and certain additional 

information, including information 

about Hg emissions from coal-fired 

EGUs that the EPA obtained pursuant to 

an information collection request (ICR) 

under the authority of CAA section 114. 

65 FR 79826–27. 

B. What is the litigation history of this 

final rule? 

Shortly after issuance of the December 

2000 finding, an industry group 

challenged that finding in the Court of 

Appeals for the D.C. Circuit (D.C. 

Circuit). Utility Air Regulatory Group 

(UARG) v. EPA, 2001 WL 936363, No. 

01–1074 (D.C. Cir. July 26, 2001). The 

D.C. Circuit dismissed the lawsuit 

holding that it did not have jurisdiction 

because CAA section 112(e)(4) provides, 

in pertinent part, that ‘‘no action of the 

Administrator * * * listing a source 

category or subcategory under 

subsection (c) of this section shall be a 

final agency action subject to judicial 

review, except that any such action may 

be reviewed under section 7607 of (the 

CAA) when the Administrator issues 

emission standards for such pollutant or 

category.’’ Id. (emphasis added). 

Pursuant to a settlement agreement, 

the deadline for issuing emission 

standards was March 15, 2005. 

However, instead of issuing emission 

standards pursuant to CAA section 

112(d), on March 29, 2005, the EPA 

issued the Section 112(n) Revision Rule 

(2005 Action). That action delisted 

EGUs after finding that it was neither 

appropriate nor necessary to regulate 

such units under CAA section 112. In 

addition, on May 18, 2005, the EPA 

issued the Clean Air Mercury Rule 

(CAMR). 70 FR 28606. That rule 

established standards of performance for 

emissions of Hg from new and existing 

coal-fired EGUs pursuant to CAA 

section 111. 

Environmental groups, states, and 

tribes challenged the 2005 Action and 

CAMR. Among other things, the 

environmental and state petitioners 

argued that the EPA could not remove 

EGUs from the CAA section 112(c) 

source category list without following 

the requirements of CAA section 

112(c)(9). 

On February 8, 2008, the D.C. Circuit 

vacated both the 2005 Action and 

CAMR. The D.C. Circuit held that the 

EPA failed to comply with the 

requirements of CAA section 112(c)(9) 

for delisting source categories. 

Specifically, the D.C. Circuit held that 

CAA section 112(c)(9) applies to the 

removal of ‘‘any source category’’ from 

the CAA section 112(c) list, including 

EGUs. The D.C. Circuit found that, by 

enacting CAA section 112(c)(9), 

Congress limited the EPA’s discretion to 

reverse itself and remove source 

categories from the CAA section 112(c) 

list. The D.C. Circuit found that the 

EPA’s contrary position would ‘‘nullify 

§ 112(c)(9) altogether.’’ New Jersey v. 

EPA, 517 F.3d 574, 583 (D.C. Cir. 2008). 

The D.C. Circuit did not reach the 

merits of petitioners’ arguments on 

CAMR, but vacated CAMR for existing 

sources because coal-fired EGUs were 

already listed sources under CAA 

section 112. The D.C. Circuit reasoned 

that even under the EPA’s own 

interpretation of the CAA, regulation of 

existing sources’ Hg emissions under 

CAA section 111 was prohibited if those 

sources were a listed source category 

under CAA section 112.6 Id. The D.C. 

Circuit vacated and remanded CAMR 

for new sources because it concluded 

that the assumptions the EPA made 

when issuing CAMR for new sources 

were no longer accurate (i.e., that there 

would be no CAA section 112 regulation 

of EGUs and that the CAA section 111 

standards would be accompanied by 

standards for existing sources). Id. at 

583–84. Thus, CAMR and the 2005 

Action became null and void. 

On December 18, 2008, several 

environmental and public health 

organizations filed a complaint in the 

U.S. District Court for the District of 

Columbia.7 They alleged that the 

Agency had failed to perform a 

nondiscretionary duty under CAA 

section 304(a)(2), by failing to 

promulgate final CAA section 112(d) 

standards for HAP from coal- and oilfired 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 elsewhere, in this 

action we are finalizing certain 

amendments to 40 CFR part 60, subpart 

Da. In developing this final rule, we 

considered the monitoring, testing, and 

recordkeeping requirements of the 

existing and revised NSPS to avoid 

duplicating requirements to the extent 

possible. 

2. CAA Section 112 

The EPA has previously developed 

other non-EGU combustion-related 

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 (Nonhazardous Solid Waste Definition Rule 

(40 CFR part 241, subpart B; 76 FR 

15456)). Electric generating units and IB 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9309 

9The CT NESHAP regulates HAP emissions from 

all simple-cycle and combined-cycle stationary CTs 

producing electricity or steam for any purpose. 

that combust fossil fuel and solid waste, 

as that term is defined by the 

Administrator pursuant to the Resource 

Conservation and Recovery Act (RCRA), 

see 76 FR 15456, will be subject to 

standards issued pursuant to CAA 

section 129 (e.g., CISWI), unless they 

meet one of the exemptions in CAA 

section 129(g)(1). Clean Air Act section 

129 standards are discussed in more 

detail below. 

The two IB (Boiler) NESHAP, the CT 

NESHAP, and this final rule will 

regulate HAP emissions from sources 

that combust fossil fuels for electrical 

power, process operations, or heating. 

The differences among these rules are 

due to the size of the units (megawatt 

(MW), megawatt-electric (MWe), or 

British thermal unit per hour (Btu/hr)), 

the boiler/furnace technology, and/or 

the portion of their electrical output (if 

any) for sale to any utility power 

distribution systems. 

Pursuant to the CAA, an EGU is ‘‘any 

fossil fuel fired combustion unit of more 

than 25 megawatts that serves a 

generator that produces electricity for 

sale. A unit that cogenerates steam and 

electricity and supplies more than onethird of its potential electric output 

capacity and more than 25 megawatts 

electrical output to any utility power 

distribution system for sale shall be 

considered an electric utility steam 

generating unit.’’ CAA section 112(a)(8). 

We consider all of the MW ratings 

quoted in the final rule to be the original 

rated nameplate capacity of the unit. We 

consider cogeneration to be the 

simultaneous production of power 

(electricity) and another form of useful 

thermal energy (usually steam or hot 

water) from a single fuel-consuming 

process. 

We consider any combustion unit, 

regardless of size, that produces steam 

to serve a generator that produces 

electricity exclusively for industrial, 

commercial, or institutional purposes 

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

electrical distribution grid) to be an IB 

unit. We do not consider a fossil fuelfired combustion unit that serves a 

generator that produces electricity for 

sale to be an EGU under the final rule 

if the size of the combustion unit is less 

than or equal to 25 MW. Units that are 

25 MW or less are likely subject to one 

of the two Boiler NESHAP. 

Because of the combustion technology 

of simple-cycle and combined-cycle 

stationary CTs (with the exception of 

integrated gasification combined cycle 

(IGCC) units that burn gasified coal or 

petroleum coke synthesis gas/syngas), 

we do not consider these CTs to be 

EGUs for purposes of this final rule.9

The December 2000 listing discussed 

above did not list natural gas-fired 

EGUs. Thus, this final rule does not 

regulate a unit that otherwise meets the 

CAA section 112(a)(8) definition of an 

EGU but that combusts natural gas 

exclusively or natural gas in 

combination with another fossil fuel 

where the natural gas constitutes 90.0 

percent or more of the average annual 

heat input during any 3 consecutive 

calendar years or 85.0 percent or more 

of the annual heat input in one calendar 

year. We consider such units to be 

natural gas-fired EGUs notwithstanding 

the combustion of some coal or oil (or 

derivative thereof) and such units are 

not subject to this final rule. 

The CAA does not define the terms 

‘‘fossil fuel-fired’’ and ‘‘fossil fuel.’’ In 

this rule, we are finalizing definitions 

for both terms for purposes of this rule. 

The definition of ‘‘fossil fuel-fired’’ will 

help determine the applicability of the 

final rule to combustion units that sell 

electricity to the utility power 

distribution system. The definition of 

‘‘fossil fuel-fired’’ establishes the 

amount of fossil fuel combustion 

necessary to make a unit ‘‘fossil fuelfired’’ and hence potentially subject to 

this final rule. These definitions will 

help determine applicability of the final 

rule to units that primarily fire nonfossil fuels (e.g., biomass) but generally 

start up using either natural gas or 

distillate oil and may use these fuels (or 

coal) during normal operation for flame 

stabilization. 

In addition, the EPA is finalizing in 

the definition of ‘‘fossil fuel-fired’’ that, 

among other things, an EGU must fire 

coal or oil for more than 10.0 percent of 

the average annual heat input during 

any 3 consecutive calendar years or for 

more than 15.0 percent of the annual 

heat input during any one calendar year 

after the applicable compliance date in 

order to be considered a fossil fuel-fired 

EGU subject to this final rule. The EPA 

has based these threshold percentage 

values on the definition of ‘‘oil-fired’’ in 

the Acid Rain Program (ARP) found at 

40 CFR 72.2. Though the EPA does not 

have annual heat input data for, for 

example, biomass co-fired EGUs 

because their use is not yet 

commonplace, we believe this 

definition accounts for the use of fossil 

fuels for flame stabilization use without 

inappropriately subjecting such units to 

this final rule. 

Units that do not meet the EGU 

definition will in most cases be 

considered IB units subject to one of the 

two Boiler NESHAP. Thus, for example, 

a biomass-fired EGU, regardless of size, 

that utilizes fossil fuels for startup and 

flame stabilization purposes only (i.e., 

less than or equal to 10.0 percent of the 

average annual heat input in any 3 

consecutive calendar years or less than 

or equal to 15.0 percent of the annual 

heat input during any one calendar 

year) is not considered to be a fossil 

fuel-fired EGU under this final rule. 

A cogeneration facility that sells 

electricity to any utility power 

distribution system equal to more than 

one-third of its potential electric output 

capacity and more than 25 MW will be 

considered an EGU if the facility is 

fossil fuel-fired as that term is defined 

in the final rule. 

We recognize that different CAA 

section 112 rules may impact a 

particular unit at different times. For 

example, the Boiler NESHAP may cover 

some cogeneration units. Such a unit 

may decide to increase or decrease the 

proportion of production output it 

supplies to the electric utility grid, thus 

causing the unit to meet the EGU 

cogeneration criteria (i.e., greater than 

one-third of its potential output capacity 

and greater than 25 MW). A unit subject 

to one of the Boiler NESHAP that 

increases its electricity output and 

meets the definition of an EGU would 

be subject to the final EGU NESHAP. 

Another rule intersection may occur 

where one or more coal- or 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 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 


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9310 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

10From 2005 National-Scale Air Toxics 

Assessment (NATA), available at http:// 

www.epa.gov/ttn/atw/nata2005/. 

incineration unit subject to emissions 

standards under CAA section 129. 

In the Non-Hazardous Solid Waste 

Definition Rule, the EPA determined 

that coal refuse from current mining 

operations is not considered to be a 

‘‘solid waste’’ if it is not discarded. Coal 

refuse that is in legacy coal refuse piles 

is considered a ‘‘solid waste’’ because it 

has been discarded. However, if 

discarded coal refuse is processed in the 

same manner as currently mined coal 

refuse, the coal refuse would not be 

considered a solid waste but instead 

would be considered a product fossil 

fuel. Therefore, the combustion of such 

material by a combustion unit would 

not subject that unit to regulation under 

CAA section 129. Instead, the unit 

would be subject to this final rule if it 

meets the definition of EGU. In the 

proposed rule, we assumed that all units 

that combust coal refuse and otherwise 

meet the definition of a coal-fired EGU 

are in fact combusting newly mined coal 

refuse or coal refuse from legacy piles 

that has been processed such that it is 

not a solid waste. We did not receive 

any information since proposal that 

would cause us to revise this 

determination in the final rule. 

Further, CAA section 129(g)(1)(B) 

exempts from regulation 

‘‘* * * qualifying small power production 

facilities, as defined in section 796(17)(C) of 

Title 16, or qualifying cogeneration facilities, 

as defined in section 796(18)(B) of Title 16, 

which burn homogeneous waste * * * for 

the production of electric energy or in the 

case of qualifying cogeneration facilities 

which burn homogeneous waste for the 

production of electric energy and steam or 

forms of useful energy (such as heat) which 

are used for industrial, commercial, heating 

or cooling purposes * * *’’ 

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 coal- and oilfired EGUs? 

This final rule protects air quality and 

promotes public health by reducing 

emissions of some of the HAP listed in 

CAA section 112(b)(1). Utilities are by 

far the largest anthropogenic source of 

Hg in the U.S. In addition, EGUs are the 

largest source of HCl, hydrogen fluoride 

(HF), and selenium (Se) emissions, and 

a major source of metallic HAP 

emissions including As, chromium (Cr), 

Ni, and others. The discrepancy is even 

greater now that almost all other major 

source categories have been required to 

control Hg and other HAP under CAA 

section 112. In 2005, U.S. EGUs emitted 

50 percent of total domestic 

anthropogenic Hg emissions, 62 percent 

of total As emissions, 39 percent of total 

cadmium (Cd) emissions, 22 percent of 

total Cr emissions, 82 percent of total 

HCl emissions, 62 percent of total HF 

emissions, 28 percent of total Ni 

emissions, and 83 percent of total Se 

emissions.10 Exposure to these HAP, 

depending on exposure duration and 

levels of exposures, is associated with a 

variety of adverse health effects. These 

adverse health effects may include 

chronic health disorders (e.g., irritation 

of the lung, skin, and mucus 

membranes; detrimental effects on the 

central nervous system; damage to the 

kidneys; and alimentary effects such as 

nausea and vomiting). Two of the HAP 

are classified as human carcinogens (As 

and CrVI) and two as probable human 

carcinogens (Cd and Ni). See 76 FR 

25003–25005 for a fuller discussion of 

the health effects associated with these 

pollutants. 

III. Appropriate and Necessary Finding 

A. Overview 

In December 2000, the EPA issued a 

finding pursuant to CAA section 

112(n)(1)(A) that it was appropriate and 

necessary to regulate coal- and oil-fired 

EGUs under CAA section 112 and added 

such units to the list of source categories 

subject to regulation under section 

112(d). The EPA found that it was 

appropriate to regulate HAP emissions 

from coal- and oil-fired EGUs because, 

among other reasons, Hg is a hazard to 

public health, and U.S. EGUs are the 

largest domestic source of Hg emissions. 

The EPA also found it appropriate to 

regulate HAP emissions from EGUs 

because it had identified certain control 

options that would effectively reduce 

HAP emissions from U.S. EGUs. The 

EPA found that it was necessary to 

regulate HAP emissions from U.S. EGUs 

under section 112 because the 

implementation of other requirements 

under the CAA will not adequately 

address the serious public health and 

environmental hazards arising from 

HAP emissions from U.S. EGUs and that 

CAA section 112 is intended to address 

HAP emissions. See 76 FR 24984–20985 

(for further discussion of 2000 finding). 

Because several years had passed 

since the 2000 finding, the EPA 

performed additional technical analyses 

for the proposed rule, even though those 

analyses were not required. These 

analyses included a national-scale Hg 

risk assessment focused on populations 

with high levels of self-caught fish 

consumption, and a set of 16 case 

studies of inhalation cancer risks for 

non-Hg HAP. The analyses confirm that 

it remains appropriate and necessary to 

regulate U.S. EGUs under section 112. 

In the preamble to the proposed rule, 

the EPA reported the results of those 

additional technical analyses. Those 

analyses confirmed the 2000 finding 

that it is appropriate to regulate U.S. 

EGUs under section 112 by 

demonstrating that (1) Hg continues to 

pose a hazard to public health because 

up to 28 percent of watersheds were 

estimated to have Hg deposition 

attributable to U.S. EGUs that 

contributes to potential exposures above 

the reference dose for methylmercury 

(MeHg RfD), a level above which there 

is increased risk of neurological effects 

in children, (2) non-Hg HAP emissions 

pose a hazard to public health because 

case studies at 16 facilities 

demonstrated that lifetime cancer risks 

at 4 of the facilities exceed 1 in 1 

million, and (3) U.S. EGUs remain the 

largest domestic source of Hg emissions 

and several HAP (e.g., HF, Se, HCl), and 

are among the largest contributors for 

other HAP (e.g., As, Cr, Ni, HCN). Thus, 

in the preamble to the proposed rule, 

the EPA found that Hg and non-Hg HAP 

emissions from U.S. EGUs pose hazards 

to public health, which confirmed the 

2000 finding and demonstrated that it 

remains appropriate to regulate U.S. 

EGUs under section 112. 

In the preamble to the proposed rule, 

the EPA also found that it is appropriate 

to regulate U.S. EGUs because (1) Hg 

emissions pose a hazard to the 

environment and wildlife, adversely 

impacting species of fish-eating birds 

and mammals, (2) acid gas HAP pose a 

hazard to the environment because they 

contribute to aquatic acidification, and 

(3) effective controls are available to 

reduce Hg and non-Hg HAP emissions 

from U.S. EGUs. 

The additional analyses reported in 

the preamble to the proposed rule also 

confirmed that it remains necessary to 

regulate U.S. EGU under CAA section 

112. These analyses demonstrated that 

(1) Hg emissions from U.S. EGUs 

remaining in 2016 are reasonably 

anticipated to pose a hazard to public 

health after imposition of other CAA 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9311 

11U.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 Coal- and Oil-Fired Electric Generating Units. 

Office of Air Quality Planning and Standards. 

November. EPA–452/R–11–009. 

12U.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. 

13U.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/ 

BCA23C5B7917F5BF8525791A0072CCA1/$File/ 

EPA-SAB-11-017-unsigned.pdf. 

14Because some watersheds with exposures 

sufficient to exceed the RfD with Hg deposition 

from U.S. EGUs alone without considering 

deposition from other sources also have U.S. EGU 

contributions of more than 5 percent of total Hg 

deposition, there is some overlap between the two 

risk metrics. This explains why the total percent of 

watersheds exceeding either risk metric is less than 

the sum of the individual risk metrics. 

15Requiring at least a 5 percent EGU contribution 

is a conservative approach given the increasing 

risks associated with incremental exposures above 

the RfD. Because we are finding 24 percent of 

watersheds with populations potentially at risk 

even using this conservative approach, we have 

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

causing a hazard to public health. 

16 76 FR 25012. 

17U.S. EPA, 2011a. 

requirements, such as the Cross-State 

Air Pollution Rule (CSAPR); (2) U.S. 

EGUs are reasonably anticipated to 

remain the largest source of Hg in the 

U.S. and thus contribute to the risk 

associated with exposure to MeHg; (3) 

Hg emissions from U.S. EGUs after 

imposition of the requirements of the 

CAA were projected to be 29 tons per 

year in 2016, similar to levels of Hg 

emitted today, indicating that further 

substantial reductions in Hg emissions 

are not reasonably anticipated without 

federal regulations on Hg from U.S. 

EGUs; (4) we cannot be certain that the 

identified cancer risks attributable to 

non-Hg emissions from U.S. EGUs will 

be addressed through imposition of the 

requirements of the CAA because 

companies can use compliance 

strategies for criteria pollutants that do 

not achieve HAP co-benefits (e.g., 

purchasing allowances in a trading 

program); and (5) we cannot ensure that 

Hg and non-Hg HAP emissions 

reductions achieved since 2005 would 

be permanent without federally binding 

regulations for Hg from U.S. EGUs. 

Since issuance of the proposed rule, 

the EPA has conducted peer reviews of 

the national-scale Hg risk assessment 

(Hg Risk TSD) and the approach for 

estimating chromium and nickel 

inhalation cancer risk in the case 

studies.11 12 The peer review of the Hg 

Risk TSD was conducted by EPA’s 

independent Science Advisory Board 

(SAB). The SAB stated that it ‘‘supports 

the overall design of and approach to 

the risk assessment and finds that it 

should provide an objective, reasonable, 

and credible determination of the 

potential for a public health hazard from 

mercury emitted from U.S. EGUs.’’ 13

SAB recommended several 

improvements to the data, methods and 

documentation of the analyses, which 

EPA has fully addressed in the revised 

Hg Risk TSD. 

As described in the revised Hg Risk 

TSD, after addressing comments from 

the peer review, the revised results 

show that up to 29 percent of modeled 

watersheds are estimated to have Hg 

deposition attributable to U.S. EGUs 

that contributes to potential exposures 

above the MeHg RfD, an increase of one 

percentage point from the results 

reported in the proposed rule. We 

conclude that Hg emissions from EGUs 

pose a hazard to public health based on 

the total of 29 percent of modeled 

watersheds at risk. Our analyses show 

that of the 29 percent of watersheds 

with population at-risk, in 10 percent of 

those watersheds U.S. EGU deposition 

alone without considering deposition 

from other sources would lead to 

potential exposures that exceed the 

MeHg RfD, and in 24 percent of those 

watersheds, total potential exposures to 

MeHg exceed the RfD and U.S. EGUs 

contribute at least 5 percent to Hg 

deposition.14 15 Each of these results 

independently supports our conclusion 

that Hg emissions from EGUs pose 

hazards to public health. 

The peer review of the approach to 

estimate Ni and Cr cancer risk in the 

case studies also supported EPA’s 

assessment. The EPA enhanced this 

analysis in response to the peer review 

and public comments. The results of 

those revised analyses show that 6 of 16 

modeled facilities have lifetime cancer 

risks greater than 1 in a million, thus 

confirming that non-Hg HAP emissions 

from U.S. EGUs remain a hazard to 

public health. Given Congress’ 

determination that categories of sources 

that emit HAP resulting in a lifetime 

cancer risk greater than 1 in a million 

should not be removed from the CAA 

section 112(c) source category list and 

should continue to be regulated under 

CAA section 112, the EPA concludes 

that risk above that level represents a 

hazard to public health. 

Based on our consideration of the 

peer reviews, public comments, and our 

updated analyses, we confirm the 

findings that Hg and non-Hg HAP 

emissions from U.S. EGUs pose hazards 

to public health and that it remains 

appropriate to regulate U.S. EGUs under 

CAA section 112. We also conclude that 

it remains appropriate to regulate U.S. 

EGUs under CAA section 112 because of 

the magnitude of Hg and non-Hg 

emissions, environmental effects of Hg 

and certain non-Hg emissions, and the 

availability of controls to reduce HAP 

emissions from EGUs. 

In addition, we conclude that the 

hazards to public health from Hg and 

non-Hg emissions from U.S. EGUs are 

reasonably anticipated to remain after 

imposition of the requirements of the 

CAA. The same is true for hazards to the 

environment. Thus, we confirm that it is 

necessary to regulate U.S. EGUs under 

CAA section 112. 

B. Peer Review of the Hg Risk TSD 

Supporting the Appropriate and 

Necessary Finding for Coal and OilFired EGUs and EPA Response 

In the preamble to the proposed rule, 

the EPA stated that ‘‘in making the 

finding that it remains appropriate and 

necessary to regulate EGUs to address 

public health and environmental 

hazards associated with emissions of Hg 

and Non-Hg HAP from EGUs, the EPA 

determined that the Hg Risk TSD 

supporting EPA’s 2011 review of U.S. 

EGU health impacts should be peerreviewed.’’ 16 We also indicated that due 

to the court-ordered schedule for the 

final rule, we planned to conduct the 

peer review as expeditiously as possible 

after issuance of the proposed rule, and 

that the results of the peer review and 

any EPA response would be published 

before the final rule. Due to the 

extension of the public comment period 

and the volume of public comments 

received on the analyses supporting the 

proposed rule, we were unable to 

publish EPA’s response prior to 

signature of the final rule. 

The EPA’s response to the peer review 

the Hg Risk TSD is fully documented in 

the revised Technical Support 

Document (TSD): National-Scale 

Assessment of Hg Risk to Populations of 

High Consumption of Self-Caught Fish 

In Support of the Appropriate and 

Necessary Finding for Coal and OilFired Electric Generating Units.17 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. 


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9312 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

18Office of Management and Budget (OMB). 2004. 

Final Information Quality Bulletin for Peer Review. 

December. Available on the Internet at http:// 

www.whitehouse.gov/omb/ 

memoranda_fy2005_m05-03. 

19 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. 

20The full list of panel members is documented 

at http://yosemite.epa.gov/sab/sabproduct.nsf/0/ 

9F048172004D93BB8525783900503486/$File/ 

Determination%20memo%20with%20addendum05.24.11.pdf. 

21 76 FR 29746. 

22 76 FR 39102. 

23 76 FR 50729. 

24U.S. EPA–SAB, 2011. Peer Review of EPA’s 

Draft National-Scale Mercury Risk Assessment. 

25See http://yosemite.epa.gov/sab/sabpeople.nsf/ 

WebCommittees/BOARD. 

1. Summary of Peer Review Process 

Peer review is consistent with EPA’s 

open and transparent process to ensure 

that the Agency’s scientific assessments 

and rulemakings are based on the best 

science available. This regulatory action 

was supported by the Hg Risk TSD, 

which is a highly influential scientific 

assessment. Therefore, the EPA 

conducted a peer review in accordance 

with OMB’s Final Information Quality 

Bulletin for Peer Review 18 as described 

below. All the materials related to the 

peer review, including the SAB’s final 

report, can be found in the docket for 

this rulemaking. 

The EPA commissioned the peer 

review through EPA’s SAB, which 

provides independent advice and peer 

review to EPA’s Administrator on the 

scientific and technical aspects of 

environmental issues. The SAB 

convened a 22-member peer review 

committee. The SAB process for 

selecting the panel began with two 

Federal Register Notices requesting 

nominations for the Mercury Review 

Panel.19 Based on nominations received, 

a list of potential panel members, along 

with bio-sketches, was posted for public 

comment on the SAB Web site 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.20 The panel held a public 

meeting in Research Triangle Park, NC, 

on June 15–17, 2011, which included 

the opportunity for public comment on 

the Hg Risk TSD and the peer review 

process.21 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 Web site 

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,22 and 

submitted a revised draft for quality 

review by the Chartered SAB before the 

end of the public comment period on 

the rule. The Chartered SAB held a 

public teleconference on September 7, 

2011, to conduct a quality review of the 

draft report; this teleconference also 

included a final opportunity for public 

comment.23 The SAB submitted its final 

report to EPA on September 29, 2011.24

Notice of all the meetings was published 

in the Federal Register and all of the 

materials discussed at the SAB 

meetings, including technical 

documents, presentations, meeting 

minutes, and draft reports were posted 

for public access on the SAB Web site 25

and were added to the docket for the 

final rule on October 14, 2011. 

2. Peer Review Charge Questions 

The EPA asked the SAB to comment 

on the Hg Risk TSD, including the 

overall design and approach and the use 

of specific models and key assumptions. 

The EPA also asked the SAB to 

comment on the extent to which 

specific facets of the assessment were 

well characterized in the Hg Risk TSD. 

The specific charge questions are listed 

below: 

Question 1. Please comment on the 

scientific credibility of the overall 

design of the mercury risk assessment as 

an approach to characterize human 

health exposure and risk associated 

with U.S. EGU mercury emissions (with 

a focus on those more highly exposed). 

Question 2. Are there any additional 

critical health endpoint(s) besides IQ 

loss, which could be quantitatively 

estimated with a reasonable degree of 

confidence to supplement the mercury 

risk assessment (see section 1.2 of the 

Mercury Risk TSD for an overview of 

the risk metrics used in the risk 

assessment)? 

Question 3. Please comment on the 

benchmark used for identifying a 

potentially significant public health 

impact in the context of interpreting the 

IQ loss risk metric (i.e., an IQ loss of 1 

to 2 points or more representing a 

potential public health hazard). Is there 

any scientifically credible alternate 

decrement in IQ that should be 

considered as a benchmark to guide 

interpretation of the IQ risk estimates 

(see section 1.2 of the Mercury Risk TSD 

for additional detail on the benchmark 

used for interpreting the IQ loss 

estimates)? 

Question 4: Please comment on the 

spatial scale used in defining 

watersheds that formed the basis for risk 

estimates generated for the analysis (i.e., 

use of 12-digit hydrologic unit code 

classification). To what extent do 

[Hydrologic Unit Code] HUC12 

watersheds capture the appropriate 

level of spatial resolution in the 

relationship between changes in 

mercury deposition and changes in 

MeHg fish tissue levels? (see section 1.3 

and Appendix A of the Mercury Risk 

TSD for additional detail on specifying 

the spatial scale of watersheds used in 

the analysis). 

Question 5: Please comment on the 

extent to which the fish tissue data used 

as the basis for the risk assessment are 

appropriate and sufficient given the 

goals of the analysis. Please comment on 

the extent to which focusing on data 

from the period after 1999 increases 

confidence that the fish tissue data used 

are more likely to reflect more 

contemporaneous patterns of Hg 

deposition and less likely to reflect 

earlier patterns of Hg deposition. Are 

there any additional sources of fish 

tissue MeHg data that would be 

appropriate for inclusion in the risk 

assessment? 

Question 6: Given the stated goal of 

estimating potential risks to highly 

exposed populations, please comment 

on the use of the 75th percentile fish 

tissue MeHg value (reflecting targeting 

of larger but not the largest fish for 

subsistence consumption) as the basis 

for estimating risk at each watershed. 

Are there scientifically credible 

alternatives to use of the 75th percentile 

in representing potential population 

exposures at the watershed level? 

Question 7: Please comment on the 

extent to which characterization of 

consumption rates and the potential 

location for fishing activity for high-end 

self-caught fish consuming populations 

modeled in the analysis are supported 

by the available study data cited in the 

Mercury Risk TSD. In addition, please 

comment on the extent to which 

consumption rates documented in 

Section 1.3 and in Appendix C of the 

Mercury Risk TSD provide appropriate 

representation of high-end fish 

consumption by the subsistence 

population scenarios used in modeling 

exposures and risk. Are there additional 

data on consumption behavior in 

subsistence populations active at inland 

freshwater water bodies within the 

continental U.S.? 

Question 8: Please comment on the 

approach used in the risk assessment of 


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26U.S. EPA–SAB, 2011. 

27 Id. 28 Id. 

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 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 concentrationresponse function used in modeling IQ 

loss. Please comment on whether EPA, 

as part of uncertainty characterization, 

should consider alternative 

concentration-response functions in 

addition to the model used in the risk 

assessment. Please comment on the 

extent to which available data and 

methods support a quantitative 

treatment of the potential masking effect 

of fish nutrients (e.g., omega-3 fatty 

acids and selenium) on the adverse 

neurological effects associated with 

mercury exposure, including IQ loss 

(detail on the concentration-response 

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 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.26 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.’’ 27 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 oil-fired EGUs, provided 

that our recommendations are fully 

considered in the revision of the 

assessment.’’ 28

The SAB report contained many 

recommendations for improving the Hg 

Risk TSD, which the SAB organized into 

three general themes: (1) Improve the 

clarity of the Hg Risk TSD regarding 

methods and presentation of results, (2) 

expand the discussion of sources of 

variability and uncertainty, and (3) deemphasize IQ loss as an endpoint. In the 

following subsection, we provide EPA’s 

response to these recommendations. 

4. The EPA’s Responses to Peer Review 

Recommendations 

In response to the peer review, the 

EPA has substantially revised the Hg 

Risk TSD. The revised Hg Risk TSD 

addresses all of the recommendations 

from the SAB and includes a detailed 

list of the specific revisions made to the 

Hg Risk TSD. Revisions in response to 

the main recommendations are 

summarized below. Italicized 

statements are the SAB’s 

recommendations, which are followed 

by EPA’s response. 

• The watershed-focus of the Hg Risk 

TSD should be clearly stated early in the 

introduction to the document. We have 

stated clearly in the introduction to the 

revised Hg Risk TSD that the focus of 

the analysis is on scenarios of high fish 

consumption by subsistence level 

fishing populations, assessed at 

watersheds where there is the potential 

for such subsistence fishing activity. 

Specifically, we modeled risk for a set 

of subsistence fisher scenarios at those 

watersheds where (a) we have measured 

fish tissue Hg data and (b) it is 

reasonable to assume that subsistencelevel fishing activity could occur. We 

emphasize the point that the analysis is 

not a representative populationweighted 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 a 

Hazard Quotient (HQ) at or above 1.5 as 

the basis for selecting potentially 

impacted watersheds. The SAB fully 

supported using HQ as the risk metric, 

but we revised the discussion in the Hg 

Risk TSD to clarify why we selected 1.5 


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29As stated in the preamble to the proposal, 

based on the current literature, exposures above the 

RfD contribute to risk of adverse effects. 

30See 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. 

31 In the Hg Risk TSD accompanying the proposed 

rule, we assumed that 100 percent of Hg in fish was 

MeHg. We derived the 0.95 conversion factor for the 

revised Hg Risk TSD to reflect that most studies 

show that more than 90 percent of total Hg in fish 

is MeHg. See Chapter 4 of U.S. EPA, 2000. 

as the benchmark. We clarified that 

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

above one) represent increasing risk of 

neurological health effects.29 We further 

clarified that the HQ is calculated to 

only one significant digit, based on the 

precision in the underlying RfD 

calculations. As a result, rounding 

convention requires that any values at 

or above 1.5 be expressed as an HQ of 

2, while any values below 1.5 (e.g., 1.49) 

be rounded to an HQ of 1. Thus, MeHg 

exposures leading to an HQ at or above 

1.5 for pregnant women are considered 

above the RfD and are associated with 

increased risk of neurological health 

effects in children born to those 

mothers. 

• Regarding the fish tissue dataset 

used in the Hg Risk TSD, clarify which 

species of Hg is reflected in the 

underlying samples and discuss the 

implications of differences across states 

in sampling protocols in introducing 

bias into the analysis. We clarified that 

in most cases, the fish tissue is 

measured for total Hg. Furthermore, 

based on the scientific literature,30 it is 

reasonable to assume that more than 

90 percent of fish tissue Hg is MeHg. 

Therefore, we incorporated an Hg 

conversion factor 31 into our exposure 

calculations to account for the fraction 

of total Hg that is MeHg in fish. We also 

expanded the discussion of uncertainty 

to address the potential for different 

sampling protocols across states to 

introduce bias into the Hg Risk TSD. 

• Additional detail should be 

provided on the characteristics of the 

fish tissue Hg dataset, including its 

derivation and the distribution of 

specific attributes across the dataset 

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

number of different waterbodies in a 

watershed, number of species reflected 

across watersheds). We included 

additional figures and tables describing 

the derivation of the 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 watershedlevel fish tissue Hg percentile estimates. 

In addition, we included tables 

summarizing key attributes of the 

dataset (e.g., distribution of fish tissue 

sample size and number of species 

across the watershed-level estimates). 

• Determine whether there is 

additional (more recent) fish tissue data 

for key states including Pennsylvania, 

New Jersey, Kentucky and Illinois where 

U.S. EGUs Hg deposition may be more 

significant. We expanded the fish tissue 

dataset by incorporating additional fish 

tissue data from the National Listing of 

Fish Advisories (NLFA), which 

included additional data for four states 

(MI, NJ, PA, and MN). We also obtained 

additional data for Wisconsin. These 

additional data expanded the number of 

watersheds in the analysis from 2,317 to 

3,141, an increase of 36 percent. The 

additional watersheds improve coverage 

in areas with high levels of U.S. EGUattributable 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 

exposures, from 29 percent of 

watersheds exceeding either risk metric 

(i.e., MeHg exposure from U.S. EGUs 

alone exceeds the RfD or total MeHg 

exposure exceeds the RfD and U.S. 

EGUs contribute at least 5 percent) in 

the revised Hg Risk TSD to 26 percent 

in the sensitivity analysis in the 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 high-end consumption 

rates for South Carolina reflect small 

sample sizes, and therefore may be more 

uncertain, (2) that the consumption 

surveys underlying the studies are older 

(i.e., mostly based on survey data from 

the 1990s) and behavior may have 

changed (i.e., consumption rates may 

have changed since the surveys were 

conducted), and (3) that consumption 

rates used in the Hg Risk TSD are 

annualized rather than seasonal rates 

and thus contribute little to overall 

uncertainty. None of these sources of 

uncertainty is associated with a 

particular directional bias (e.g., neither 

systematically higher nor lower risk). 

• Verify whether the consumption 

rates are daily values expressed as 

annual averages and whether they are 

‘‘as caught’’ or ‘‘as prepared.’’ We 

carefully reviewed the studies 

underlying the fish consumption rates 

used in the Hg Risk TSD and verified 

that the rates are annual averages of the 

daily consumption rates and that they 

represent as prepared estimates. We also 

expanded the explanation of the 

exposure calculations to describe more 

completely the exposure factors and 

equation used to generate the average 

daily MeHg intake estimates for the 

subsistence scenarios. 

• Explain the criteria for exclusion of 

fish less than 7 inches in length from 

analysis. We provided the rationale for 

the 7-inch cutoff for edible fish used in 

the Hg Risk TSD. Seven inches 

represents a minimum size limit for a 

number of key edible freshwater fish 

species established at the state level. For 

example, Pennsylvania establishes 7 

inches as the minimum size limit for 

both trout and salmon (other edible fish 

species such as bass, walleye and 

northern pike have higher minimum 

size limits). The impact of the 7-inch 

cutoff is likely to be quite small, as only 

6 percent of potential fish samples were 

excluded due to this criterion. 

• Identify the number of watersheds 

excluded from the analysis due to the 

criterion for excluding watersheds with 

less than 25 members of a source 

population. The SAB was generally 

supportive of the approach used for 

identifying watersheds with the 

potential for subsistence activity, 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 


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32 In the Revised Hg Risk TSD, this population is 

also referred to as the ‘‘typical female subsistence 

consumer.’’ 

33This change led to a very small increase in the 

number of watersheds with populations potentially 

at-risk. In the Hg Risk TSD accompanying the 

proposed rule, approximately 4 percent of modeled 

watersheds were excluded based on the SES-based 

filtering criteria. 

watersheds. Because the female 

subsistence fishing scenario does not 

differentiate with regard to ethnicity or 

socio-economic 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 high-consuming female 

scenario included in the Hg Risk TSD.32

However, the female subsistence fishing 

scenario is applied to all watersheds, 

while in the scenario for the highconsuming low-income female angler, 

we only evaluated watersheds with a 

population of at least 25 low-income 

females. The female subsistence fishing 

scenario provides greater coverage 

geographically than the high-consuming 

low-income female scenario. As 

described in the revised Hg Risk TSD, 

the EPA made this change in response 

to SAB’s concerns regarding the 

potential exclusion of watersheds with 

fewer than 25 individuals and regarding 

coverage for high-end recreational fish 

consumption.33

• 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 

exposure associated with current 

deposition. If the fish tissue Hg levels 

are too high due to either previous Hg 

deposition or non-air sources of Hg, 

then the absolute level of exposure 

attributed to both total Hg deposition 

and U.S. EGU-attributable Hg deposition 

will be biased high. However, the 

percent contribution from U.S. EGUs 

will not be affected as it depends 

entirely on deposition. The EPA took 

steps to minimize the potential for these 

biases by (1) only using fish tissue Hg 

samples from after 1999, and (2) 

screening out watersheds that either 

contained active gold mines or had 

other substantial non-U.S. EGU 

anthropogenic emissions of Hg. The 

SAB concluded that the EPA’s approach 

to minimizing the potential for these 

biases to affect the results of the Hg Risk 

TSD is sound. In addition, we 

conducted several sensitivity analyses 

to gauge the impact of excluding 

watersheds with the potential for nonEGU Hg loading. 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 terms of the 

degree to which they are reflected in the 

design of the risk assessment and the 

impact that they might have on risk 

estimates. These include: (1) The 

geographic patterns of populations of 

subsistence fishers, including how this 

factor interacts with the limited 

coverage we have for watersheds with 

our fish tissue Hg data, (2) the protocols 

used by states in collecting fish tissue 

Hg data, (3) body weights for 

subsistence fishing populations and the 

impact that this might have on exposure 

estimates, and (4) preparation and 

cooking methods which affect the 

conversion of fish tissue Hg levels (as 

measured) into ‘‘as consumed’’ values. 

We expanded the discussion of sources 

of variability in the revised Hg Risk TSD 

to more fully address these sources of 

variability. The Hg Risk TSD 

quantitatively reflected many aspects of 

variability, including spatial and 

temporal variability in Hg emissions, Hg 

deposition, fish tissue Hg levels, and 

subsistence behavior. After evaluating 

the aspects of variability assessed 

qualitatively in the Hg Risk TSD such as 

temporal response in fish tissue, we do 

not believe that quantitatively 

incorporating any of these aspects 

would substantially change the risk 

results given the stated goal of the 

analysis to identify watersheds where 

potential exposures to MeHg from selfcaught fish consumption could exceed 

the RfD. 

• Additional sources of uncertainty 

should be discussed in terms of their 

potential impact on risk estimates. 

These include: (1) Emissions inventory 

used in projecting total and U.S. EGUattributable 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 highconsuming recreational fishers), and (8) 

application of the RfD to low SES 

populations and concerns that this 

could low-bias the risk estimates. We 

expanded the discussion of sources of 

uncertainty presented in the revised 

TSD to address more fully these sources 

of uncertainty and the potential impact 

on risk estimates. Regarding these eight 

additional sources of uncertainty, we 

have (1) evaluated the uncertainties in 

the emissions and determined that 

while an important source of 

uncertainty, we are not able to quantify 

emissions uncertainty in the risk 

analysis, but have determined that the 

emissions inventories and emissions 

models represent the best available 

methods for predicting Hg emissions in 

the U.S., (2) evaluated the uncertainties 

in the Hg deposition predictions and 

determined that while an important 

source of uncertainty, we are not able to 

quantify uncertainty in Hg deposition in 

the Hg Risk TSD. Moreover, the CMAQ 

model used to estimate deposition is 

based on peer reviewed science and 

represents the best available method for 

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

evaluated the ability of the Mercury 

Maps-based approach for relating Hg 

deposition to MeHg in fish to capture 

Hg hotspots and determined that while 

finer resolution deposition modeling 

might reveal additional areas with 

elevated deposition, the 12 kilometer 


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34The 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. 

35Since the time of the analyses conducted in 

support of the proposed rule, the EPA updated IPM 

modeling to reflect the most recently available 

information, including public comments and the 

final CSAPR (see IPM Documentation for further 

details on these updates, which is available in the 

docket). Compared to the modeling conducted at 

proposal, these updates are projected to result in 

greater reductions in criteria pollutants, and also to 

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

emissions. Based on the revised projection for 2016, 

the EPA estimates that U.S. EGUs would emit 27 

tons of Hg, as compared to the 29 tons we modeled 

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

difference to substantially change the mercury risks 

reported in the preamble to the proposed rule, as 

this represents less than a 10 percent reduction in 

Hg emissions. 

36The 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. 

(km) deposition modeling matches well 

with the watershed size selected for the 

analysis, and thus the use of 12 km 

deposition estimates with the Mercury 

Maps based approach will not be a large 

source of uncertainty, (4) evaluated the 

limited coverage that we have with fish 

tissue Hg data for watersheds in the U.S. 

and implications for the Hg Risk TSD 

and based on the SAB’s 

recommendations, we supplemented the 

coverage of watersheds by obtaining 

additional fish tissue Hg samples for 

areas heavily impacted by U.S. EGU 

deposition, thus reducing the 

uncertainty in the analysis, (5) 

evaluated the uncertainty in the 

preparation factor and determined that 

the level of uncertainty is low, and as 

such would have minimal impact on the 

risk estimates, (6) evaluated the 

uncertainty resulting from the 

proportionality assumption used to 

relate changes in Hg deposition to 

changes in fish tissue Hg levels at the 

watershed-level, and determined, based 

both on quantitative sensitivity analyses 

and qualitative assessments, that this 

source of uncertainty is not likely to 

greatly influence the results, and is not 

likely to have a specific directional bias, 

(7) evaluated the uncertainty related to 

characterization of the spatial locations 

of subsistence populations and 

determined that uncertainty could be 

reduced by focusing the risk estimates 

on female subsistence fishing 

populations, which are assumed to have 

the potential to fish in all watersheds, 

in response to SAB’s concerns regarding 

potential exclusion of watersheds with 

fewer than 25 individuals and (8) 

evaluated the potential impact of the 

uncertainty in application of the RfD to 

low SES populations. The EPA 

determined that due to the method used 

in calculating the RfD, we have 

confidence that the RfD provides 

protection for low SES populations. 

• Expand the sensitivity analyses 

(over those included in the original risk 

assessment) to address uncertainty 

related to the use of the 75th percentile 

fish tissue Hg value (at each watershed) 

as the core risk estimate. Based on the 

SAB’s recommendation, we added a 

sensitivity analysis using the median 

fish tissue Hg estimate (at the watershed 

level). This sensitivity analysis showed 

that use of the median fish tissue Hg 

concentration instead of the 75th 

percentile resulted in a relatively small 

decrease (i.e., 10 percent) in the 

estimates of watersheds with 

populations potentially at-risk, and did 

not substantially change the conclusions 

of the risk assessment. 

C. Summary of Results of Revised Hg 

Risk TSD of Risks to Populations With 

High Levels of Self-Caught Fish 

Consumption 

Based on the recommendations we 

received from the SAB, we revised the 

quantitative analysis of risk to 

subsistence fishing populations with 

high levels of fish consumption. Our 

revision to the quantitative risk results 

reflects three key recommendations 

from the SAB, including (1) addition of 

824 watersheds based on additional fish 

tissue Hg sample data we obtained from 

states and the National Listing of Fish 

Advisories, (2) application of a 0.95 

adjustment factor to the reported fish 

tissue Hg concentrations to account for 

the fraction that is MeHg, and (3) 

inclusion of all watersheds with fish 

samples that meet the filtering criteria 34

in representing potential exposures 

associated with increased risk of 

neurologic health effects for female 

subsistence fishing populations. 

Based on these revisions, our 

estimates of the number and percent of 

modeled watersheds with populations 

potentially at-risk from exposure to 

EGU-attributable MeHg changed from 

those presented in the preamble to the 

proposed rule.35 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 EGUattributable MeHg increased from 672 to 

917 (an increase of 36 percent). For this 

same scenario, the total percent of 

modeled watersheds with populations 

potentially at-risk from either risk 

metric (i.e., MeHg exposure from U.S. 

EGUs alone exceeds the RfD or total 

MeHg exposure exceeds the RfD and 

U.S. EGUs contribute at least 5 percent) 

increased from 28 percent estimated at 

proposal to 29 percent after addressing 

SAB recommendations. The increase in 

the total percent of modeled watersheds 

with populations potentially at-risk 

using the expanded geographic coverage 

of watersheds provides additional 

confidence that emissions of Hg from 

U.S. EGUs pose a hazard to public 

health. For the 99th percentile 

consumption scenario, the percent of 

modeled watersheds with populations 

potentially at-risk from total potential 

exposures to MeHg that exceed the RfD 

and U.S. EGUs contribute at least 5 

percent increased from 22 percent to 24 

percent. For the 99th percentile 

consumption scenario, the percent of 

modeled watersheds with populations 

potentially at-risk based on Hg 

deposition from U.S. EGUs alone 

decreased from 12 percent to 10 percent. 

The additional sensitivity analyses 

conducted in response to the SAB peer 

review showed that the estimates of the 

percent of modeled watersheds with 

populations potentially at-risk are 

robust to alternative assumptions about 

both the watersheds included in the 

analysis and the selection of the 50th 

percentile or 75th percentile fish tissue 

Hg level. Sensitivity analyses excluding 

entire states with the potential for 

historical loadings of Hg from non-air 

sources 36 resulted in an increase from 

29 percent to 33 percent in the total 

percent of modeled watersheds with 

populations potentially at-risk 

exceeding either risk metric (i.e., U.S. 

EGUs alone or total potential exposures 

to MeHg exceed the RfD and U.S. EGUs 

contribute at least 5 percent). Including 

only watersheds in the top 25th 

percentile of U.S. EGU deposition 

resulted in an increase in the total 

percent of modeled watersheds with 

populations potentially at-risk 

exceeding either risk metric, from 29 

percent to 30 percent. Using the 50th 

percentile fish tissue Hg level resulted 

in a decrease in the total percent of 

modeled watersheds with populations 

potentially at-risk exceeding either risk 

metric, from 29 percent to 26 percent. 

On balance, these sensitivity analyses 

do not substantially reduce the percent 

of modeled watersheds with 

populations potentially at-risk, and thus 

confirm the finding that Hg emissions 

from U.S. EGUs pose a hazard to public 

health. In fact, given the broader 

coverage of modeled watersheds in the 

revised analysis, we have even greater 

confidence in our finding that Hg 


srobinson on DSK4SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9317 

37U.S. Environmental Protection Agency— 

Science Advisory Board (U.S. EPA–SAB). 2010. 

Review of EPA’s draft entitled, ‘‘Risk and 

Technology Review (RTR) Risk Assessment 

Methodologies: For Review by the EPA’s Science 

Advisory Board with Case Studies—MACT I 

Petroleum Refining Sources and Portland Cement 

Manufacturing’’. EPA–SAB–10–007. May. Available 

on-line at: http://yosemite.epa.gov/sab/ 

sabproduct.nsf/ 

4AB3966E263D943A8525771F00668381/$File/EPASAB-10-007-unsigned.pdf. 

38See 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. 

39U.S. EPA, 2011c. 

emissions from U.S. EGUs pose a hazard 

to public health. 

D. Peer Review of the Approach for 

Estimating Cancer Risks Associated 

With Cr and Ni Emissions in the U.S. 

EGU Case Studies of Cancer and NonCancer Inhalation Risks for Non-Hg 

HAP and EPA Response 

As explained in the preamble to the 

proposed rule, the EPA submitted for 

peer review its characterization of the 

chemical speciation for the emissions of 

Cr and Ni used in the non-Hg HAP 

inhalation risk case studies. The 

remaining aspects of the non-Hg HAP 

case study risk assessments used 

methods that were previously peer 

reviewed. Specifically, the 

methodologies used to conduct the nonHg case studies are consistent with 

those used to conduct inhalation risk 

assessments under EPA’s Risk and 

Technology Review (RTR) program. 

Because the RTR assessments are 

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 2010.37 The report endorsed the 

risk assessment methodologies used in 

the program, and made a number of 

technical recommendations for EPA to 

consider as the RTR program evolves. 

The EPA’s case studies identified Cr 

and Ni emissions as the key drivers of 

the estimated inhalation cancer risks for 

EGUs. Because these results hinged on 

specific scientific interpretations of data 

used to characterize EGU emissions of 

Cr and Ni, the EPA conducted a letter 

peer review of its analysis and 

interpretation of those data relative to 

the quantification of inhalation risks 

associated with Cr and Ni emissions 

from U.S. EGUs. The following sections 

describe the peer review process, 

enumerate the peer review charge 

questions presented to the peer review 

panel, summarize the key 

recommendations from the peer review, 

and summarize our responses to those 

recommendations. 

1. Summary of Peer Review Process 

The EPA asked three independent, 

external peer reviewers representing 

government, academic and the private 

sector to review of the methods for 

developing inhalation cancer risk 

estimates associated with emissions of 

Cr and Ni compounds from coal- and 

oil-fired EGUs in support of the 

appropriate and necessary finding. The 

approaches and rationale for the 

technical and scientific considerations 

used to derive inhalation cancer risks 

were summarized in the draft document 

entitled, ‘‘Methods to Develop 

Inhalation Cancer Risk Estimates for 

Chromium and Nickel Compounds.’’ 

The peer reviewers received several 

charge questions (three questions on Cr 

and two questions on Ni, which are 

provided below) on the technical and 

scientific relevance of the approaches 

used to develop the inhalation unit risk 

estimates. The EPA also provided 

information on Cr speciation profiles for 

different industrial sources, as well as 

information on the Ni speciation of PM 

from oil-fired EGUs. 

2. Peer Review Charge Questions 

Below, we present the charge 

questions posed to the peer reviewers to 

help guide their review and 

development of recommendations to 

EPA on key issues relevant to the 

characterization of risks from EGU 

emissions containing either Cr or Ni 

compounds. 

The EPA asked three questions 

regarding Cr and Cr compounds: 

Question 1: Do EPA’s judgments 

related to speciated Cr emissions 

adequately take into account the 

available Cr speciation data? 

Question 2: Has EPA selected the 

species of Cr (i.e., hexavalent Cr, Cr(VI)) 

that accurately represents the toxicity of 

Cr and Cr compounds? 

Question 3: Are the assumptions used 

in past analysis scientifically defensible, 

and are there alternatives that EPA 

should consider for future analysis? 

The EPA asked two questions 

regarding Ni and Ni compounds: 

Question 1: Do EPA’s judgments 

related to speciated Ni emissions 

adequately take into account available 

speciation data, including recent 

industry spectrometry studies? 

Question 2: Based on the speciation 

information available and on what we 

know about the health effects of Ni and 

Ni compounds, and taking into account 

the existing Unit Risk Estimates (URE) 

values (i.e., values derived for EPA’s 

Integrated Risk Information System 

(IRIS), California Environmental 

Protection Agency (Cal EPA) and Texas 

Commission on Environmental Quality 

(TCEQ)), the EPA has provided several 

approaches 38 to derive unit risk 

estimates that may be more 

scientifically defensible than those used 

in past analyses. Which of the options 

presented would result in more accurate 

and defensible characterization of risks 

from exposure to Ni and Ni compounds? 

Are there alternative approaches that 

EPA should consider? 

3. Summary of Peer Review Findings 

and Recommendations 

Regarding Cr and Cr compounds, all 

three reviewers considered Cr(VI) as the 

species likely to be driving cancer risks 

based on solid evidence from the health 

effects database for Cr and Cr 

compounds. All three authors also 

considered EPA’s use of the average of 

the range of the available speciation 

data (i.e., 12 percent and 18 percent 

Cr(VI) contained in coal- and oil-fired 

EGUs, respectively) as a reasonable 

approach for the derivation of default 

speciation profiles to be used when 

there is no speciation data available. All 

reviewers agreed that there is high 

uncertainty associated with the 

variability in the speciation data 

available for Cr (e.g., range of 

approximately 4 to 23 percent Cr(VI) 

from coal-fired units). One of the 

reviewers recommended several 

additional studies for EPA’s 

consideration; the EPA considered these 

in finalizing the report. 

Regarding Ni and Ni compounds, the 

reviewers agreed with the views of the 

international scientific bodies, which 

consider Ni compounds carcinogenic as 

a group. One reviewer recommended 

that the EPA review several additional 

Ni speciation data that suggests that 

sulfidic Ni compounds (which the 

reviewer considered as the most potent 

carcinogens within the group of all Ni 

compounds) are present at low levels in 

emissions from EGUs. In addition, this 

reviewer pointed out that there is a 

recently proposed model that may 

explain the differences in carcinogenic 

potential across Ni compounds. 

4. The EPA’s Responses to Peer Review 

Recommendations 

We summarize EPA’s basic responses 

to the peer review comments below, 

first for Cr-related issues, and second for 

Ni-related issues, which are reflected in 

the revised document.39


srobinson on DSK4SPTVN1PROD with RULES2
9318 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

40 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. 

41Huggins 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. 

42Oller A. 2002. ‘‘Respiratory carcinogenicity 

assessment of soluble nickel compounds.’’ Environ 

Health Perspect. 110:841–844. 

43Heller 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. 

44 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. 

45 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.ossup-med.com/content/5/1/7. 

46Texas 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. 

47U.S. EPA, 1991. Integrated Risk Information 

Service (IRIS) assessment for nickel subsulfide. 

Available at: http://www.epa.gov/iris/subst/ 

0273.htm. 

48Haber LT, Allen BC, Kimmel CA. 1998. ‘‘NonCancer Risk Assessment for Nickel Compounds: 

Issues Associated with Dose-Response Modeling of 

Inhalation and Oral Exposures.’’ Toxicol Sci. 

43:213–229. 49National Toxicology Program (NTP). 1996. 

Technical Report Series No. 454, Toxicology and 

carcinogenesis studies of nickel sulfate 

hexahydrate. July. Available online at http:// 

ntp.niehs.nih.gov/ntp/htdocs/LT_rpts/tr454.pdf. 

a. Cr and Cr Compounds 

In agreement with the peer reviewers 

and based on the health effects 

information available for Cr, the EPA 

assigns high confidence in the 

assumption that Cr(VI) is the 

carcinogenic species driving the risk of 

Cr-emitting facilities. In agreement with 

the reviews, the EPA considers 

derivation of default speciation profiles 

based on the mass of Cr(VI) a reasonable 

approach. As suggested by one of the 

reviewers, the EPA reviewed two 

potentially relevant studies, one of 

which showed coal combustion 

emissions containing as much as 43 

percent Cr(VI),40 which suggests that the 

EPA’s quantitative approach could 

actually underestimate Cr(VI) inhalation 

risks. However, the other study 

reviewed by EPA on speciation of Cr in 

coal combustion showed Cr(VI) 

percentage levels close to detection 

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

which was close to the limit of detection 

in this study).41 Thus, the more recent 

speciation data available is unlikely to 

reduce the uncertainty of the Cr 

speciation analyses used by EPA as the 

bases for risk characterization analysis. 

In agreement with the peer reviewers, 

the EPA also recognizes that the 

confidence in the default speciation 

profiles is low because the profiles are 

based on a limited data set with a wide 

range of percentages of Cr(VI) across the 

different samples. 

b. Ni and Ni Compounds 

Based on the views of the major 

scientific bodies mentioned above and 

the peer reviewers that commented on 

EPA’s approaches to risk 

characterization of Ni compounds, the 

EPA considers all Ni compounds to be 

carcinogenic as a group and the EPA 

does not consider Ni speciation or Ni 

solubility to be strong determinants of 

Ni carcinogenicity. These scientific 

bodies also recognize that based on the 

data available, the precise Ni 

compound(s) responsible for the 

carcinogenic effects in humans is not 

always clear, and that there may be 

differences in the potential toxicity and 

carcinogenic potential across Ni 

compounds. Nevertheless, studies in 

humans indicate that various mixtures 

of Ni compounds (including Ni sulfate, 

sulfides and oxides, alone or in 

combination) encountered in the Ni 

refining industries may cause cancer in 

humans, and there is no reason to 

expect anything different from this for 

mixtures of Ni compounds from other 

emission sources. One of the reviewers 

suggested we consider views by some 

authors that believe that water soluble 

Ni, such as Ni sulfate, should not be 

considered a human carcinogen. This 

view is based primarily on a negative Ni 

sulfate 2-year rodent bioassay by the 

National Toxicology Program (NTP) 

(which is different from the positive 2- 

year NTP bioassay for Ni 

subsulfide).42 43 44 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, the EPA identified a recent 

review 45 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 

TCEQ 46 for all Ni compounds as a 

group, rather than the one derived by 

the Integrated Risk Information System 

(IRIS, 1991) 47 specifically for Ni 

subsulfide. The third reviewer did not 

comment on an alternative approach. 

Considering this, to develop our 

primary risk estimate, the EPA decided 

to use a health protective approach by 

applying 100 percent of the current IRIS 

URE for Ni subsulfide, rather than 

assuming that 65 percent of the total 

mass of emitted Ni might be Ni 

subsulfide, as used in previous analyses. 

We used the IRIS URE value because 

IRIS values are preferred given the 

conceptual consistency with EPA risk 

assessment guidelines and the level of 

peer review that such values receive. 

We used 100 percent of the IRIS value 

because of the concerns about the 

potential carcinogenicity of all forms of 

Ni raised by the major national and 

international scientific bodies, and 

recommendations of the peer reviewers. 

Nevertheless, taking into account that 

there are potential differences in 

toxicity and/or carcinogenic potential 

across the different Ni compounds, and 

given that two URE values have been 

derived for exposure to mixtures of Ni 

compounds that are two to three fold 

lower than the IRIS URE for Ni 

subsulfide, the EPA also considers it 

reasonable to use a value that is 50 

percent of the IRIS URE for Ni 

subsulfide for providing an estimate of 

the lower end of a plausible range of 

cancer potency values for different 

mixtures of Ni compounds. 

Although this report focused 

primarily on cancer risks associated 

with emissions containing Ni 

compounds, it is important to note that 

comparative quantitative analyses of 

non-cancer 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.48 49

E. Summary of Results of Revised U.S. 

EGU Case Studies of Cancer and NonCancer Inhalation Risks for Non-Hg 

HAP 

Based on the results of the peer 

review and public comments on the 

non-Hg case study chronic inhalation 

risk assessment, we made several 

changes to the emissions estimates, 

dispersion modeling, and risk 

characterization for the modeled case 

study facilities. Key changes include (1) 

changes in emissions, (2) changes in 

stack parameters for some facilities 

based on new data received during the 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9319 

50A risk level of 1 in a million implies a 

likelihood that up to one person, out of one million 

equally exposed people would contract cancer if 

exposed continuously (24 hours per day) to the 

specific concentration over 70 years (an assumed 

lifetime). This would be in addition to those cancer 

cases that would normally occur in an unexposed 

population of one million people. 

51When the lower end of the cancer potency 

range for Ni was used to develop risk estimates, 5 

of the 16 facilities had maximum cancer risks 

exceeding 1 in a million, and the maximum 

individual cancer risk for any single facility fell to 

10 in a million. 

52The target-organ-specific hazard index (TOSHI) 

is a metric used to assess whether there is an 

appreciable risk of deleterious (noncancer) effects to 

a specific target organ due to continuous inhalation 

exposures over a lifetime. If a TOSHI value is less 

than or equal to one, such effects are unlikely. For 

TOSHI values greater than one, there is an 

increased risk of such effects. 

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 16 

case study facilities was 20 in a million, 

driven by Ni emissions from the one 

case study facility with oil-fired EGUs. 

Of the facilities with coal-fired EGUs, 

five facilities had maximum individual 

cancer risks greater than one in a 

million 50 (the highest was five in a 

million), with the risk from four due to 

emissions of Cr(VI) and the risk from 

one due to emissions of Ni.51 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) 52 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 likely 

underestimates true maximum risks for 

the source category. 

Based on the fact that six U.S. EGUs 

were estimated to meet or exceed the 

CAA section 112(c)(9) criterion of one in 

a million, EGUs cannot be removed 

from the list of source categories to be 

regulated under CAA section 112. 

F. Public Comments and Responses to 

the Appropriate and Necessary Finding 

1. Legal Aspects of Appropriate and 

Necessary Finding 

a. History of Section 112(n)(1)(A) 

Comment: One commenter provided a 

detailed history of EPA’s regulatory 

actions concerning EGUs and 

implementation of CAA section 

112(n)(1)(A). The same commenter 

implies that the EPA’s 2000 appropriate 

and necessary finding and listing of 

EGUs was flawed because the Agency 

did not comply with CAA section 

307(d) rulemaking process. The 

commenter sought review of the 2000 

notice in the U.S. Court of Appeals for 

the District of Columbia Circuit, which 

was dismissed by the D.C. Circuit. 

Utility Air Regulatory Group v. EPA, No. 

01–1074 (D.C. Cir. July 26, 2001). The 

commenter then characterizes at length 

the 2005 EPA action that revised the 

interpretation of CAA section 

112(n)(1)(A) and, which the D.C. Circuit 

concluded illegally removed EGUs from 

the CAA section 112(c) list of sources 

that must be regulated under CAA 

section 112. See New Jersey v. EPA, 517 

F.3d 574 (D.C. Cir. 2008). The 

commenter notes that the D.C. Circuit 

did not rule on the legal correctness or 

the sufficiency of the factual record 

supporting EPA’s 2000 listing decision 

or on the factual correctness of EPA’s 

later decision to reverse its CAA section 

112(n)(1)(A) determination. The 

commenter noted further that the D.C. 

Circuit indicated that the listing 

decision could be challenged when the 

Agency issued the final CAA section 

112(d) standards pursuant to CAA 

section 112(e)(4). The commenter 

concluded by asserting that the Agency 

could not ignore the history associated 

with the regulation of EGUs under 

section 112 and that two earlier 

dockets—Docket ID. No. A–92–55 and 

Docket ID. No. EPA–HQ–OAR–2002– 

0056—are also part of this long 

rulemaking effort and must be 

accounted for in conjunction with 

Docket No. EPA–HQ–OAR–2009–0234 

if all pertinent material and comments 

are to be part of the rulemaking record. 

Response: The commenter 

characterizes the regulatory history of 

the rule EPA proposed on May 3, 2011. 

To the extent that characterization is 

inconsistent with the lengthy regulatory 

history EPA provided in the preamble to 

the May 3, 2011 rule, we disagree. We 

address several of the statements in 

more detail below. 

First, the commenter makes much of 

the fact that the EPA did not go through 

CAA section 307(d) notice and comment 

rulemaking when making the 

appropriate and necessary finding and 

listing decision in 2000. However, the 

commenter’s complaint is without 

foundation. The CAA does not require 

CAA section 307(d) rulemaking for 

listing decisions. In fact, CAA section 

112(e)(4) specifically provides that 

listing decisions may only be challenged 

‘‘when the Administrator issues 

emission standards for such * * * 

[listed] category.’’ Second, the 

commenter challenged the listing 

decision in the U.S. Court of Appeals for 

the District of Columbia Circuit (Court) 

and, on July 26, 2001, the Court granted 

EPA’s motion to dismiss that action 

based on the plain language of CAA 

section 112(e)(4). Moreover, in addition 

to the 2000 notice, the EPA clearly 

articulated its basis for listing EGUs in 

this proposed rule, which is consistent 

with CAA section 307(d), and the 

commenter was provided an ample 

opportunity to comment. Finally, the 

commenter asserts that the rulemaking 

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 FR 15994 (March 29, 

2005), and the reconsideration of the 

Section 112(n) Revision Rule, 71 FR 

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 

the 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, the EPA has come 

to a single repeated conclusion that 

HAP emissions from EGUs pose little or 

no risk to public health. Based on this 

conclusion, the EPA has properly 

chosen not to require EGUs to install 

expensive, new pollution control 

equipment to control HAP emissions. 

The commenter asserts that, in this 

proposed rule, the EPA shifts its 

opinion on the health impacts of EGU 

HAP emissions 180 degrees and now 

seeks to impose sweeping regulatory 

requirements on all power plants. 

According to the commenter, the EPA’s 

newfound concern about HAP 

emissions from EGUs is not based on 

new and different assessments of the 

public health consequences of EGU 

HAP emissions but instead on health 

benefits from the reduction of nonhazardous air pollutants, primarily PM, 

which the Agency is required to regulate 

under other provisions of the CAA. One 


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commenter stated that for decades, the 

EPA set primary ambient air quality 

standards that protect public health 

with an adequate margin of safety, CAA 

section 109(b)(1), and set secondary 

standards that are [sic] ‘‘requisite to 

protect the public welfare from any 

known or anticipated adverse effects 

associated with the presence of such air 

pollutant in the ambient air,’’ CAA 

109(b)(2). The commenter notes that 

even if EPA now views those past PM 

standards as inadequate, the EPA has 

ongoing regulatory proceedings in 

which it can address any perceived 

health concerns. The commenter 

concludes that regulation of EGU HAP 

emissions under CAA section 112 is an 

unlawful way to address those concerns. 

Response: The commenter is incorrect 

in its assertion that the Agency has 

consistently concluded that HAP 

emissions from EGUs do not present a 

hazard to public health. In the 2000 

finding, the Agency concluded that HAP 

emissions from coal- and oil-fired EGUs 

do pose a hazard to public health and 

determined that it was appropriate and 

necessary to regulate such units under 

CAA section 112. As a result of that 

finding, the EPA added coal- and oilfired 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, 

the EPA conducted additional extensive 

quantitative and qualitative analyses, 

which confirm that it remains 

appropriate and necessary to regulate 

EGUs under CAA section 112. Among 

other things, those analyses demonstrate 

that emissions from coal- and oil-fired 

EGUs continue to pose a hazard to 

public health. The commenter also fails 

to note that the EPA found that HAP 

emissions from EGUs pose a hazard to 

the environment as well. 

The commenter seems confused about 

the basis for the Agency’s appropriate 

and necessary finding because it 

maintains that the EPA made the 

appropriate and necessary finding based 

on the health co-benefits attributable to 

PM reductions that will be achieved as 

a result of the Agency’s regulation of 

HAP emissions from EGUs. Nowhere in 

the May 2011 proposal does EPA state 

that it based the appropriate and 

necessary finding on hazards to public 

health attributable to PM emissions. The 

commenter’s allegation lacks 

foundation. The appropriate and 

necessary finding unmistakably focuses 

on the hazards to public health and 

hazards to the environment associated 

with HAP emissions from EGUs. 

Comment: One commenter stated that 

CAA section 112 required EPA to make 

a risk-based determination in order to 

regulate HAP. According to the 

commenter, the EPA may regulate 

substances ‘‘reasonably * * * 

anticipated to result in an increase in 

mortality or increase in serious illness’’ 

to a level that protects public health 

with an ‘‘ample margin of safety.’’ 

According to the commenter, the EPA 

has regulated a number of HAP emitted 

from industrial source categories other 

than EGUs. 

As for EGUs, according to the 

commenter, the EPA found that the 

combustion of fossil fuels produces 

extremely small emissions of a broad 

variety of substances that are present in 

trace amounts in fuels and that are 

removed from the gas stream by control 

equipment installed to satisfy other 

CAA requirements. The commenter 

stated that the EPA, in past reviews, 

found that these HAP emissions did not 

pose hazards to public health. See 48 FR 

15076, 15085 (1983) (radionuclides). the 

commenter further stated that ‘‘[i]n the 

case of Hg specifically, the EPA found 

that ‘‘coal-fired power plants * * * do 

not emit mercury in such quantities that 

they are likely to cause ambient mercury 

concentration to exceed’’ a level that 

‘‘will protect public health with an 

ample margin of safety.’’ 40 FR 48297– 

98 (October 19, 1975) (Hg); 52 FR 8724, 

8725 (March. 19, 1987) (reaffirming Hg 

conclusion). 

According to the commenter, in the 

late 1980s, the EPA was concerned that 

its prior risk assessments of individual 

HAP emissions from fossil-fuel-fired 

power plants may not reflect the total 

risks posed by all HAP emitted by those 

sources. The commenter states that the 

EPA modeled the risks posed by all 

HAP emitted by power plants (very 

much like the analyses the Agency 

would conduct for the Utility Study ten 

years later). The commenter asserts that 

the modeling again failed to identify 

threats to public health that warranted 

regulation under an ‘‘ample margin of 

safety’’ test. 

Response: The commenter’s 

statements concerning the pre-1990 

CAA are not relevant to the current 

action. Congress enacted CAA section 

112(n)(1) as part of the 1990 

amendments to the Act. That provision 

requires, among other things, that the 

Agency evaluate the hazards to public 

health posed by HAP emissions from 

fossil-fuel fired EGUs. Had Congress 

concluded, as commenter appears to 

assert, that HAP emissions from EGUs 

did not pose a hazard to public health 

or the environment, it defies reason that 

Congress would have required EPA to 

conduct the three studies at issue in 

CAA section 112(n)(1) (titled ‘‘Electric 

utility steam generating units’’) and 

regulate EGUs under section 112 if the 

Administrator determined in her 

discretion that it was appropriate and 

necessary to do so. The Agency 

complied with the statutory mandates in 

CAA section 112(n)(1) in conducting the 

studies and reasonably exercised its 

discretion in making the appropriate 

and necessary finding. 

We acknowledge that Congress treated 

radionuclide emissions from EGUs 

differently. For radionuclides from 

EGUs (and certain other sources), 

Congress included CAA section 

112(q)(3), which authorizes but does not 

require the Agency to maintain the 

regulations of radionuclides in effect 

prior to the 1990 amendments. The fact 

that Congress made an exception for 

radionuclides and no other HAP from 

EGUs further demonstrates that the 

HAP-related actions EPA took with 

regard to EGUs prior to the 1990 

amendments to the CAA are not 

germane. 

As for the commenter’s statements 

about Hg emissions from EGUs, we find 

their conclusions wholly inconsistent 

with CAA section 112(n)(1). That 

provision is titled ‘‘Electric utility steam 

generating units,’’ and it directs EPA to 

conduct two Hg-specific studies. See 

CAA sections 112(n)(1)(B) and 

112(n)(1)(C). The commenter’s 

suggestion that the EPA could or should 

rely on assessments of Hg from EGUs 

conducted prior to the 1990 

amendments is not tenable. 

Finally, the commenter stated that the 

EPA conducted a risk assessment of all 

HAP from EGUs prior to the 1990 

amendments and that the Agency did 

not identify any HAP that failed the 

‘‘ample margin of safety’’ test. The 

commenter did not cite the study or 

provide any information to support the 

statements so we are unable to respond 

to the alleged study directly; however, 

the risk assessments conducted in 

support of the appropriate and 

necessary finding, as well as the 2000 

finding, demonstrate that HAP 

emissions from EGUs pose hazards to 

public health and the environment. 

b. Interpretation of ‘‘Appropriate’’ and 

‘‘Necessary’’ 

Comment: One commenter stated that 

in the preamble to the proposed rule, 

the EPA sets out its ‘‘interpretation of 

the critical terms in CAA section 

112(n)(1),’’ arguing that this latest 

interpretation is ‘‘wholly consistent 

with the CAA’’ and with the Agency’s 

earlier ‘‘2000 finding.’’ See 76 FR 24976, 

24986 (May 3, 2011). The commenter 

stated that throughout the proposal EPA 

tries to suggest that it is returning to 


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53 Id. at 24,977/3. 

54 65 FR 79830. 

some earlier, ‘‘correct’’ interpretation of 

CAA section 112(n)(1) set forth in its 

2000 action. See, e.g., 76 FR 24989 

(‘‘The Agency’s interpretation of the 

term ‘appropriate’ * * * is wholly 

consistent with the Agency’s 

appropriate finding in 2000’’); id. at 

24992 (‘‘Our interpretation of the 

necessary finding is reasonable and 

consistent with the 2000 finding’’). 

According to the commenter, the EPA 

did not provide in 2000 any 

interpretation of what it now 

characterizes as the ‘‘critical terms’’ of 

section 112(n)(1). See, e.g., 70 FR 15999 

n.13 (the ‘‘2000 finding does not 

provide an interpretation of the phrase 

‘after imposition of the requirements of 

the Act’ ’’); id. at 16000/2 (in 2000, the 

EPA ‘‘did not provide an interpretation 

of the term ‘appropriate’ ’’); 76 FR 24992 

(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.* * *’’ 53

Response: The commenter disagrees 

with certain statements in the preamble 

to the proposed rule that provide that 

the Agency’s interpretation of CAA 

section 112(n)(1) is reasonable and 

consistent with the 2000 finding. It is 

difficult to decipher the exact complaint 

that the commenter has with EPA’s 

proposed rule in this regard, but the 

commenter does assert that ‘‘the Agency 

did not provide in 2000 any 

interpretation of what it now 

characterizes as the ‘‘critical terms’’ of 

CAA section 112(n)(1).’’ The 

commenter’s assertion lacks foundation. 

Although the 2000 finding did not 

provide detailed interpretations of the 

regulatory terms at issue, it discussed 

the types of considerations relevant to 

the appropriate and necessary inquiry. 

For example, it is clear that in 2000, the 

Agency was concerned with the then 

current hazards to public health and the 

environment when assessing whether it 

was appropriate to regulate EGUs under 

section 112.54 In addition, when 

evaluating whether it was necessary to 

regulate utilities, the Agency stated that 

it was necessary to regulate HAP 

emissions from U.S. EGUs under section 

112 because the implementation of the 

other requirements of the Act would not 

adequately address the serious public 

health and environmental hazards 

arising from HAP emissions from EGUs. 

The Agency also specifically noted that 

‘‘section 112 is the authority intended to 

address’’ hazards to public health and 

the environment posed by HAP 

emissions. Id. 

The detailed interpretation set forth in 

the preamble to the proposed rule is 

consistent with the 2000 finding, but 

EPA does not assert that the 

interpretation is in any way necessary to 

support the factual conclusions reached 

in the 2000 finding. Instead, we noted 

in the preamble to the proposed rule 

that our interpretation is consistent with 

the 2000 finding because in 2005 we 

interpreted the statute in a manner that 

was not consistent with the 2000 

finding. The commenter has provided 

no legal support for its position that the 

Agency erred in interpreting the statute 

in a manner that is consistent with a 

prior factual finding. 

Comment: Several commenters assert 

that in the 1990 amendments to the 

Clean Air Act, Congress directed the 

EPA to base its determination regarding 

regulation of fossil-fuel-fired generating 

units on consideration of any adverse 

public health effects identified in the 

study mandated by the first sentence of 

section 112(n)(1)(A) and that Congress 

did not dictate in section 112(n)(1)(A) 

that the EPA must regulate electric 

utility steam generating units under 

section 112. 

According to the commenters the 

sponsor of the House bill that became 

section 112(n)(1)(A) provides an 

explanation that contradicts the EPA’s 

approach to regulating EGUs: 

Pursuant to section 112(n), the 

Administrator may regulate fossil fuel fired 

electric utility steam generating units only if 

the studies described in section 112(n) 

clearly establish that emissions of any 

pollutant, or aggregate of pollutants, from 

such units cause a significant risk of serious 

adverse effects on the public health. Thus, 

* * * he may regulate only those units that 

he determines—after taking into account 

compliance with all provisions of the act and 

any other Federal, State, or local regulation 

and voluntary emission reductions—have 

been demonstrated to cause a significant 

threat of serious adverse effects on the public 

health. 

136 Cong. Rec. H12,934 (daily ed. Oct. 

26, 1990) (statement of Rep. Michael 

Oxley). 

The commenters stated that the EPA 

position is premised on the assumption 

that ‘‘regulation under section 112’’ 

necessarily means ‘‘regulation under 

112(d)’’ and falsely premised on the 

assumption that source categories listed 

by operation of section 112(n)(1)(A) 

cannot be regulated differently. The 

commenters conclude that the language 

of section 112(n)(1)(a) reflects Congress’ 

intent that ‘‘regulation of HAP from 

EGUs was not intended to operate under 

section 112(d) but was instead intended 

to be tailored to the findings of the 

utility study mandated by section 

112(n)(1)(A).’’ 

Response: The commenters maintain 

that the Agency’s interpretation of CAA 

section 112(n)(1) is flawed in many 

respects. The primary support for one 

commenter’s arguments against EPA’s 

interpretation, including in the 

comment above, is legislative history in 

the form of statements from one 

Congressman, Representative Oxley. 

The Supreme Court has repeatedly 

stated that the statements of one 

legislator alone should not be given 

much weight. See Brock v. Pierce 

County, 476 U.S. 253, 263 (1986) 

(finding that ‘‘statements by individual 

legislators should not be given 

controlling effect, but when they are 

consistent with the statutory language 

and other legislative history, they 

provide evidence of Congress’ intent.’’) 

(emphasis added) (citation omitted); 

Garcia, et al., v. U.S., 469 U.S. 70, 78 

(1984), citing Zuber v. Allen, 396 U.S. 

168, 187 (1969) (reiterating its prior 

findings, the Court indicated that 

isolated statements ‘‘are ‘not impressive 

legislative history.’ ’’); Weinberger, et al., 

v. Rossi et al., 456 U.S. 25, 35 (declining 

to make a ruling based on ‘‘one isolated 

remark by a single Senator’’); Consumer 

Product Safety Comm., et al. v. GTE 

Sylvania, Inc., et al., 447 U.S. 102, 117– 

118 (1980) (declining to give much 

weight to isolated remarks of one 

Representative); Chrysler Corp. v. 

Brown, et al., 441 U.S. 281, 311 (1979) 

(finding that ‘‘[t]he remarks of a single 

legislator, even the sponsor, are not 

controlling in analyzing legislative 

history.’’); Zuber, 396 U.S. at 186 

(concluding that ‘‘[f]loor debates reflect 

at best the understanding of individual 

Congressmen.’’); and U.S. v. O’Brien, 

391 U.S. 367, 384 (1968) (in evaluating 

the statements of a handful of 

Congressmen, the Court concluded that 

‘‘[w]hat motivates one legislator to make 

a speech about a statute is not 

necessarily what motivates scores of 

others to enact it. * * *.’’). As these 

cases show, the Supreme Court does not 

give weight to the statements of an 

individual legislator, except when the 

statements are supported by other 

legislative history and the clear intent of 

the statute. The commenters cited no 

case law that would support reliance on 

such limited legislative history. 

The commenter has not cited any 

other legislative history to support 


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55 In addition, the EPA only considered CAA 

requirements in the Utility Study and this was the 

correct approach because Congress knew how to 

require consideration of non-Federal requirements 

when directing EPA to conduct a study or 

assessment. See CAA section 112(n)(5) (Congress 

required EPA to conduct an assessment of hydrogen 

sulfide from oil and gas extraction activities and 

provided that the assessment ‘‘shall include review 

of existing State and industry control standards, 

techniques and enforcement.’’). 

Representative Oxley’s statement, and 

the lack of additional support makes the 

statement of little utility or import 

under the case law. In fact, there does 

not appear to be anything in the House, 

Senate, or Committee Reports that 

supports Oxley’s statement. The lack of 

support for Oxley’s statement in the 

Committee Report is particularly telling 

since, as the commenter notes, the 

House and Senate bills required 

different approaches to regulating EGUs 

under section 112, with the Senate bill 

requiring EGUs be regulated prior to the 

Utility Study. In fact, legislative 

statements from Senator Durenberger, a 

supporter of the Senate version, 

demonstrate that others would almost 

certainly not have agreed with Oxley’s 

interpretation. For example, Senator 

Durenberger stated, ‘‘It seems to me 

inequitable to impose a regulatory 

regime on every industry in America 

and then exempt one category, 

especially a category like power plants 

which are a significant part of the air 

toxics problem.’’ 

Senator Durenberger discussed the 

negotiations with the Administration 

and the industry push to avoid 

regulation, including industry 

arguments for not regulating Hg from 

U.S. EGUs: 

The utility industry continued to 

adamantly oppose [regulation under section 

112]. First, they argued that mercury isn’t 

much of an environmental problem. But as 

the evidence mounted over the summer and 

it became clear that mercury is a substantial 

threat to the health of our lakes, rivers and 

estuaries and that power plants are among 

the principal culprits, they changed their 

tactic. Now they are arguing that mercury is 

a global problem so severe that just cleaning 

up U.S. power plants won’t make enough of 

a difference to be worth it. They’ve gone from 

‘we’re not a problem’ to ‘you can’t regulate 

us until you address the whole global 

problem.’ Recasting an issue that way is not 

new around here. So, it is not a surprise. But 

it does suggest the direction in which this 

debate will be heading in the next few years. 

136 Cong. Rec. 36062 (October 27, 

1990). 

Senator Durenberger also explained 

why the House version was adopted: 

Given that a resolution of the difficult 

issues in the conference were necessary to 

conclude work on this bill, the Senate 

proposed to recede to the House provision 

which was taken from the original 

administration bill. It provides for a 3-year 

study of utility emissions followed by 

regulation to the extent that the 

Administrator finds them necessary. 

Id. 

Senator Durenberger’s statements 

indicate that it is unlikely that he would 

agree with Oxley’s interpretation of 

CAA section 112(n)(1), a provision that 

provides the Agency with considerable 

discretion, and nothing indicates that 

others in the Senate (or for that matter 

anyone else in the House) would agree 

with that interpretation. Given the 

Supreme Court’s views on the use of 

such limited legislative history, the EPA 

reasonably declined to consider (or even 

discuss) the legislative history in the 

preamble to the proposed rule and we 

believe it would be improper to ascribe 

Representative Oxley’s statements to the 

entire Congress. 

Moreover, Representative Oxley’s 

statement directly conflicts with the 

statutory text. Representative Oxley 

stated that ‘‘[the Administrator may 

regulate only those units that he 

determines—after taking into account 

compliance with all 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.55

The legislative history the 

commenters rely on is not controlling. 

The Agency believes that it has 

reasonably interpreted section 

112(n)(1)(A), for all the reasons 

described herein and in the proposal. 

The commenters also cite 

Representative Oxley’s statements as 

support for alternative interpretations of 

CAA section 112(n)(1). We believe that 

any arguments that rely on such limited 

legislative history are without merit. 

Comment: One commenter stated that 

the EPA does acknowledge that, in 

many significant respects, its new 

interpretation of CAA section 112(n)(1) 

‘‘differs from that set forth’’ in the 

Agency’s 2005 rulemaking, but argues 

that its change of position is 

permissible. See 76 FR 24988/1 (‘‘[T]o 

the extent our interpretation differs from 

that set forth in the 2005 Action, we 

explain the basis for that difference and 

why the interpretation, as set forth in 

this preamble, is reasonable.’’). In 

support, commenters note that the EPA 

cites National Cable & 

Telecommunication Ass’n v. Brand X 

Internet Services, 545 U.S. 967 (2005). 

The commenters agree that it is true 

that, in Brand X Internet Services, the 

Supreme Court explained that, if an 

agency ‘‘adequately explains the reasons 

for a reversal of policy,’’ such change is 

‘‘not invalidating,’’ since the ‘‘whole 

point of Chevron is to leave the 

discretion provided by the ambiguities 

of a statute with the implementing 

agency.’’ 545 U.S. at 981 (internal 

quotations omitted). The commenters 

maintain that all Brand X Internet 

Services was saying is that ‘‘[a]gency 

inconsistency is not a basis for declining 

to analyze the agency’s interpretation 

under the Chevron framework.’’ Id. 

According to the commenter, it is not 

enough that the EPA has purported to 

‘‘explain’’ why it has abandoned the 

interpretation of CAA section 112(n)(1) 

adopted in 2005. The commenter states 

that under the first step of Chevron, the 

Agency’s latest interpretation must still 

be consistent with congressional intent. 

See Chevron v. NRDC, 467 U.S. at 842– 

43. The commenters state that under the 

second step of Chevron, if there is 

discretion for EPA to exercise in 

interpreting the ‘‘critical terms’’ of CAA 

section 112(n)(1), the Agency must 

properly define the range of that 

discretion and then act reasonably in 

exercising that discretion. See Chevron, 

467 U.S. at 843; see also Village of 

Barrington, Ill. v. Surface 

Transportation Bd., No. 09–1002 (D.C. 

Cir. Mar. 15, 2011).The commenters 

allege that the EPA failed to properly 

define and exercise the scope of its 

discretion. In each instance, the 

commenter maintains that the Agency 

has departed from the correct 

interpretation of CAA section 112(n)(1) 

that it adopted in 2005, seizing instead 

upon a new approach that is contrary to 

the plain language of the CAA itself, as 

interpreted after considering the 

statements of Representative Oxley. 

Response: The commenter appears to 

argue that the EPA’s interpretation of 

CAA section 112(n)(1) is not consistent 

with the plain language of the statute, 

implying that the statute is 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). 


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However, as noted above, much of the 

commenter’s argument that the plain 

language of the statute precludes EPA’s 

interpretation is based on the 

unpersuasive legislative history 

discussed above. As explained in the 

preamble to the proposed rule, the 

statute directs the Agency to determine 

whether it is appropriate and necessary 

to regulate EGUs under section 112. As 

the D.C. Circuit has held, the terms 

‘‘appropriate’’ and ‘‘necessary’’ are very 

broad terms. Because these terms are 

broad they are susceptible to different 

interpretations. We believe we have 

reasonably interpreted the appropriate 

and necessary language in section 

112(n)(1)(A). To the extent that 

interpretation differs from the one set 

forth in 2005, we have fully explained 

the basis for such changes. See 76 FR 

24986–24993 (setting forth the Agency’s 

interpretation of section 112(n)(1)). 

Furthermore, we properly considered 

the scope of our discretion in 

interpreting the statute as explained in 

detail in the preamble to the proposed 

rule. We believe the interpretation set 

forth in the preamble to the proposed 

rule is consistent with the Act and, 

therefore, the Agency should be 

afforded deference pursuant to National 

Cable & Telecommunication Ass’n v. 

Brand X Internet Services, 545 U.S. 967 

(2005). 

Comment: A number of commenters 

agreed with the Agency’s interpretation 

of section 112(n)(1) and the terms 

appropriate and necessary. The 

commenters also agreed that the EPA’s 

interpretation of that provision was 

reasonable and consistent with the 

statute. 

Response: We agree with the 

commenters and appreciate their 

support. 

Comment: One commenter asserts 

that the EPA’s ultimate motivation for 

rejecting its prior interpretation of CAA 

section 112(n)(1) and embracing this 

flawed new approach is made clear from 

the very outset of the proposal. 

According to the commenter, the EPA 

touts the fact that ‘‘one consequence’’ of 

the MACT rule would be that the 

‘‘market for electricity in the U.S. will 

be more level’’ and ‘‘no longer skewed 

in favor of the higher polluting units 

that were exempted from the CAA at its 

inception on Congress’ assumption that 

their useful life was near an end.’’ See 

76 FR 24979/2. The MACT rule would 

‘‘require companies to make a 

decision—control HAP emissions from 

virtually uncontrolled sources’’ or else 

‘‘retire these sometimes 60 year old 

units and shift their emphasis to more 

efficient, cleaner modern methods of 

generation, including modern coal-fired 

generation.’’ Id. 

The commenter stated that this 

remarkably forthright statement 

establishes that the underlying basis for 

EPA’s proposal to regulate EGUs under 

CAA section 112 is not to address any 

‘‘hazards to public health’’ that might be 

attributed to the emission by EGUs of 

HAP listed under CAA section 112(b). 

Rather, according to commenter, the 

EPA is utilizing the regulation of EGUs 

under CAA section 112 as a means to an 

entirely different end: To force the 

imposition of controls that will also 

have the result of reducing non-HAP 

emissions (primarily PM) or force the 

shutdown of those units for which the 

cost of such controls would be 

prohibitive. At the same time, according 

to commenter, the EPA tacitly 

acknowledges that it cannot hope to 

make out a case that the regulation of 

EGU HAP emissions is ‘‘appropriate and 

necessary’’ within the meaning of CAA 

section 112(n)(1). The commenter 

asserts that the only HAP whose healthrelated benefits EPA quantifies is Hg. 

Elsewhere, the commenter stated that 

the EPA contends there are ‘‘additional 

health and environmental effects’’ 

attributable to HAP other than Hg, but 

admits that it has ‘‘not quantified’’ those 

risks due supposedly to ‘‘insufficient 

information.’’ See 76 FR 24999/2. With 

respect to Hg the commenter stated that 

the benefits are so questionable and 

miniscule, some $4 million to $6 

million (given a 3 percent discount 

rate), that compared to the total social 

costs of the rule (i.e., nearly $11 billion) 

the rule cannot be justified were EPA 

properly to interpret CAA section 

112(n)(1) and undertake the sort of 

regulatory analysis Congress intended. 

The commenter stated that the reason 

that the EPA touts in this rulemaking 

the health benefits EPA attributes to the 

reduction of non-hazardous air 

pollutants (again, primarily PM), the 

regulation of which is authorized under 

provisions of the CAA apart from CAA 

section 112, is to elide the inconvenient 

truth regarding the truly trivial nature of 

the benefits attributable to HAP 

regulation itself. The commenter 

concludes that the EPA distorts CAA 

section 112(n)(1)(A) ‘‘beyond all 

recognition.’’ 

One commenter stated that the EPA is 

directed by CAA section 112(n)(1)(A) to 

study the ‘‘hazards to public health 

anticipated to occur as a result of 

emissions’’ by EGUs of ‘‘pollutants 

listed under subsection (b) of this 

section’’—i.e., HAP and HAP alone. 

Thereafter, the EPA is authorized to 

regulate EGU HAP emissions if, and 

only if, they determine that ‘‘such 

regulation’’ of HAP emissions is 

‘‘appropriate and necessary’’ to address 

the ‘‘hazards to public health’’ that may 

be attributable to HAP emissions. 

According to the commenter, by 

contrast, in this rulemaking, the EPA 

has seized upon the fact that the 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 nonHAP 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 nonHAP emissions, such as PM. The 

commenter also implies that regulation 

of HAP is nothing more than a straw 

man and that the Agency’s ultimate goal 

is to regulate other pollutants, and 

specifically PM. These allegations are 

wholly without merit. The Agency has 

conducted comprehensive technical 

analyses that confirm that HAP 

emissions from EGUs pose a hazard to 

public health. The analyses are 

discussed at length elsewhere in this 

final rule, and a review of the proposed 

and final rules utterly refutes 

commenter’s assertion that PM 

reductions form the basis for the 

appropriate and necessary finding. In 

addition, the commenter appears to 

ignore the Agency’s findings concerning 

the hazards to public health and the 

environment posed by HAP emissions 

simply because the Agency is not able 

to quantify many of the benefits 

associated with reductions of HAP 

emissions from EGUs or because the 

estimated HAP benefits that are 

quantified are small in relation to the 

co-benefits achieved through reductions 

in non-HAP air pollutants, such as PM 

and SO2, which are surrogates for 

certain HAP. The Agency is regulating 

EGUs pursuant to section 112(d) for all 

of the reasons explained in the preamble 

and discussed elsewhere in this 

response to comments. The commenter 

fails to recognize that the statute neither 

requires a cost-benefit analysis prior to 

finding it appropriate and necessary to 

regulate EGUs, nor requires such 

analysis prior to setting emission 

standards. Indeed, Congress expressly 

precluded consideration of costs when 

setting MACT floors. As explained 

below, the EPA does not believe that it 

is appropriate to consider costs when 


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56U.S. EPA. 1997. Mercury Study Report to 

Congress. EPA–452/R–97–003. December. 

57NAS, 2000. 

determining whether to regulate EGUs 

under CAA section 112. 

Comment: One commenter stated that 

the EPA has ignored the language and 

intent of CAA section 112(n)(1)(A), as 

interpreted based on Representative 

Oxley’s statements, and that the 

Agency’s interpretation of this provision 

violates step one of Chevron. Under 

Chevron where the ‘‘intent of Congress 

is clear,’’ that is the ‘‘end of the matter,’’ 

for both the implementing agency and a 

reviewing court ‘‘must give effect to the 

unambiguously expressed intent of 

Congress.’’ Chevron, 467 U.S. at 842–43. 

The commenter asserts that the 

legislative history of CAA section 

112(n)(1)(A) ‘‘sheds considerable light 

on Congress’ unique approach to 

regulation of EGUs under CAA § 112.’’ 

According to the commenter, on April 3, 

1990, the Senate passed S. 1630. The 

Senate bill would have required EPA to 

list EGUs under CAA section 112(c) and 

to regulate them under the MACT 

provisions of CAA section 112(d). See S. 

1630 section 301, 3 1990 Legis. Hist. at 

4407. Thereafter, the House of 

Representatives passed a modified 

version of S. 1630 on May 23, 1990. 

This House version substantially 

changed the provisions of CAA section 

112 as they applied to EGUs. See 1 1990 

Legis. Hist. at 572–73. The House 

version was virtually identical to the 

current CAA section 112(n)(1)(A), and 

was ultimately adopted by the 

conference committee, enacted by 

Congress and signed into law. 

According to the commenter, Congress 

expressly rejected the ‘‘list-under-(c)- 

and-regulate-under-(d)’’ approach that 

S. 1630 would have applied to EGUs, 

and that Congress did choose to apply 

to other source categories. The 

commenter stated that the EPA’s 

interpretation that the Agency is 

‘‘required to establish emission 

standards for EGUs consistent with the 

requirements set forth in section 112(d)’’ 

(Id. at 24,993/3) fails to take the 

legislative history into account, and in 

a footnote, the commenter states that the 

Agency erred by not addressing the 

legislative history as it did in the 2005 

action. 

Response: For the reasons stated 

above, we believe commenter’s reliance 

on the single statement of one legislator 

is flawed. In addition, in a footnote the 

commenter stated that the EPA 

recognized ‘‘that it had to address’’ the 

legislative history in its 2005 action, and 

that the EPA erred in this case because 

we did not address the legislative 

history. The commenter cites no case 

law to support its contention that an 

Agency must ‘‘address’’ unpersuasive 

legislative history. Further, in the 2005 

action, the EPA relegated to a footnote 

the Oxley statement that commenter 

relies on so heavily even though the 

statement supported the interpretation 

we provided in that rule. We recognized 

then what the commenter fails to 

recognize now, which is that the Agency 

cannot argue that the meaning of CAA 

section 112(n)(1)(A) is clear based on 

the statements of one legislator. 

Furthermore, the Agency’s 

interpretation does not violate Chevron 

Step 1. The terms ‘‘appropriate’’ and 

‘‘necessary’’ are ambiguous. The 

statements of a lone legislator do not 

transform those ambiguous words into a 

Chevron Step 1 situation. 

Moreover, the commenter’s assertion 

that Congress unambiguously defined 

the factors to consider in making the 

appropriate determination is without 

merit. We fully explain in the preamble 

to the proposed rule the basis for the 

Agency’s interpretation, and we are not 

revising that interpretation based on the 

comments received. 

Finally, the EPA notes that the 

sentence concerning regulation under 

CAA section 112(d) that the commenter 

quotes from the preamble states, in full: 

‘‘Congress did not exempt EGUs from 

the other requirements of section 112 

and, once listed, the EPA is required to 

establish emission standards for EGUs 

consistent with the requirements set 

forth in section 112(d), as described 

above.’’ 76 FR 24993 (emphasis added). 

The EPA discusses requirements to 

regulate section 112(c) listed sources 

under section 112(d) in response to 

other comments. 

c. Consideration of Both Environmental 

Effects and Health Effects From Other 

Sources 

Comment: Several commenters stated 

that the EPA acts contrary to 

congressional intent when the Agency 

considers itself ‘‘thereby authorized to 

consider ‘environmental effects’ and the 

effects of HAP emissions from non-EGU 

sources, in making its ‘appropriate and 

necessary’ finding under subparagraph 

(n)(1)(A).’’ 

Commenters assert that the EPA 

misreads CAA section 112(n)(1)(B) and 

(C) to inject environmental effects in the 

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

determination. According to one 

commenter the plain language of CAA 

section 112(n)(1) establishes that 

regulation of EGUs is to be predicated 

solely on ‘‘hazards to public health’’ 

attributable to HAP emissions. The 

legislative history providing that the 

EPA ‘‘may regulate [EGUs] only if the 

studies described in section 112(n) 

clearly establish that emissions of any 

pollutant * * * from such units cause 

a significant risk of serious adverse risk 

to the public health’’ confirms that plain 

language. See Oxley Statement at 1416– 

17. The commenter further stated that 

nothing on the face of CAA section 

112(n)(1)(A) indicates that Congress 

intended that the EPA should (or must) 

take into account any additional 

information that might be developed 

through the other studies mentioned in 

subparagraphs (n)(1)(B) and (C) (i.e., the 

Mercury Study 56 and the NAS 

Study 57), such as HAP emissions from 

non-EGU sources. The commenter also 

identified other provisions of section 

112 that specifically require 

consideration of environmental effects 

and states that Congress would have 

requires such consideration in CAA 

section 112(n)(1) if it had wanted EPA 

to consider environmental effects. 

The commenter makes a related 

assertion that the EPA acts contrary to 

congressional intent by assuming 

authority to assess the ‘‘‘hazard to 

public health or the environment [from] 

HAP emissions from EGUs alone’ or the 

‘result of HAP emissions from EGUs in 

conjunction with HAP emissions from 

other sources’’’ (citing 76 FR at 24,988/ 

1). According to the commenter, the 

only evident basis for the Agency’s 

interpretation that, in making its 

‘‘appropriate and necessary’’ finding, 

the EPA can (and should) take into 

account HAP emissions from sources 

other than EGUs, is that the Mercury 

Study authorized by CAA 112(n)(1)(B) 

references ‘‘mercury emissions from 

* * * municipal waste combustion 

units, and other sources, including area 

sources,’’ in addition to EGUs. The 

commenter asserts, however, that 

subparagraph (n)(1)(A) identifies the 

Utility Study as the sole study to inform 

EPA’s ‘‘appropriate and necessary’’ 

finding. The commenter states that if 

Congress had intended that the EPA 

take into account information developed 

through the Mercury Study, Congress 

‘‘would not have specified that the EPA 

was to predicate its ‘appropriate and 

necessary’ finding on the ‘results of the 

study required by this subparagraph’ 

(n)(1)(A).’’ 

Commenter also cites to a number of 

other section 112 provisions that 

expressly address environmental effects 

and the commenter states the only 

conclusion to draw from the inclusion 

in those provisions and the absence of 

such language in section 112(n)(1)(A) is 

that Congress intended public health to 

be the only basis for the appropriate and 

necessary finding. 


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58Several 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. 59 76 FR 24986–87. 60 76 FR 24988. 

Response: The commenter again relies 

in part on the statements of one 

legislator to attack EPA’s reasoned 

interpretation of an ambiguous statute. 

To the extent the commenter’s 

arguments rely on this limited evidence, 

we refer to the response above. As we 

stated above, CAA section 112(n)(1) is 

an ambiguous statutory provision; thus, 

the EPA’s interpretation, not 

commenter’s, is entitled to considerable 

deference if it is a reasonable reading of 

the statute. Chevron, 467 U.S. at 843–44. 

For the reasons described herein and in 

the proposal, we believe that we have 

reasonably interpreted the statutory 

terms at issue here. The Agency directs 

attention to section III.A. of the 

proposed rule, which includes a 

thorough discussion of the Agency’s 

interpretation of the relevant statutory 

terms. To the extent the commenters 

disagree with EPA’s interpretations, the 

EPA refers back to its discussion in the 

proposal and responds to the comments 

as follows. 

The commenter appears to maintain 

that the EPA must interpret the scope of 

the appropriate and necessary finding 

solely in the context of the CAA section 

112(n)(1)(A) Utility Study, such that 

only hazards to public health and only 

EGU HAP emissions may be considered. 

The commenter incorrectly conflates the 

requirements for the Utility Study with 

the requirement to regulate EGUs under 

CAA section 112 if EPA determines it is 

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); 58 see also 76 FR 24988. 

We further explained in the preamble to 

the proposed rule that it was reasonable 

to interpret the scope of the appropriate 

and necessary finding in the context of 

all three studies required under CAA 

section 112(n)(1) because the provision 

is title ‘‘Electric utility steam generating 

units.’’ 59 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 and 

solely attributable to EGUs. 

The commenter stated that Congress 

specifically told EPA when it wanted 

EPA to consider adverse environmental 

effects in CAA section 112 and cites to 

several provisions of the Act that 

require consideration of adverse 

environmental effects. The commenter 

ignores CAA section 112(n)(1)(B), which 

directs the Agency to consider adverse 

environmental effect. In any event, even 

were we to view section 112(n)(1)(A) in 

isolation, as the commenter suggests, we 

still maintain that we can consider 

adverse environmental effects under 

112(n)(1)(A). Nothing in section 

112(n)(1)(A) precludes consideration of 

environmental effects. Congress 

required the Agency to assess whether 

it is appropriate and necessary to 

regulate EGUs under section 112. We 

believe that adverse environmental 

effects can be considered in the 

appropriate analysis. Congress 

specifically directed the Agency to 

consider adverse environmental effects 

when delisting source categories 

pursuant to section 112(c)(9), and thus 

we believe it is reasonable to consider 

such effects when determining whether 

it is appropriate to regulate such units 

under section 112, especially given that 

Congress did not limit our appropriate 

and necessary inquiry to the Utility 

Study. See CAA section 112(c)(9)(B)(ii). 

Moreover, the other provisions of 

CAA section 112 that specifically 

discuss environmental effects have 

purposes that are distinguishable from 

CAA section 112(n)(1), and we do not 

believe one can reasonably draw the 

conclusion that the commenter does 

when comparing those provisions to 

CAA section 112(n)(1)(A). The lack of a 

requirement to consider environmental 

effects in CAA section 112(n)(1)(A) does 

not equate to a prohibition on the 

consideration of environmental effects 

as the commenter concludes. The EPA 

maintains that it reasonably concluded 

that we should protect against identified 

or potential adverse environmental 

effects absent clear direction to the 

contrary. 

Concerning the consideration of the 

cumulative effect of HAP emissions 

from EGUs and other sources, we 

provided a reasonable interpretation of 

the statute and noted that our 

interpretation, unlike commenters, does 

not ‘‘ignore the manner in which public 

health and the environment are affected 

by air pollution. An individual that 

suffers adverse health effects as the 

result of the combined HAP emissions 

from EGUs and other sources is harmed, 

irrespective of whether HAP emissions 

from EGUs alone would cause the 

harm.’’ 60

d. Finding for All HAP To Be Regulated 

Comment: Several commenters stated 

that for those EGU HAP for which the 

Agency makes no CAA section 

112(n)(1)(A) determination, their 

regulation under CAA section 112 is not 

authorized. For example, one 

commenter maintains that the Agency 

could regulate HAP emissions from 

EGUs under CAA section 112(n). 

Accordingly, to the extent that the EPA 

reads CAA section 112, as construed by 

National Lime Ass’n, as compelling it to 

regulate all HAP emitted by EGUs, 

should the Agency make an 

‘‘appropriate and necessary’’ 

determination under CAA section 

112(n)(1)(A) with respect to a single 

HAP (e.g., Hg), the EPA stands poised to 

commit a fundamental legal error that 

will condemn the final rule on review. 

Cf., e.g., PDK Laboratories, Inc., 362 

F.3d at 797–98; Holland v. Nat’l Mining 

Ass’n, 309 F.3d at 817 (where an agency 

applies a Court of Appeals 

‘‘interpretation * * * because it 

believed that it had no choice’’ and that 

it ‘‘was effectively ‘coerced’ to do so,’’ 

then the agency ‘‘cannot be deemed to 

have exercised its reasoned judgment’’). 

Response: We do not agree with the 

commenter’s assertion that Congress 

intended EPA to regulate only those 

EGU HAP emissions for which an 

appropriate and necessary finding is 


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made, and the commenter has cited no 

provision of the statute that states a 

contrary position. The EPA reasonably 

concluded that we must find it 

‘‘appropriate’’ to regulate EGUs under 

CAA section 112 if we determine that a 

single HAP emitted from EGUs poses a 

hazard to public health or the 

environment. If we also find that 

regulation is necessary, the Agency is 

authorized to list EGUs pursuant to 

CAA section 112(c) because listing is 

the logical first step in regulating source 

categories that satisfy the statutory 

criteria for listing under the statutory 

framework of CAA section 112. See New 

Jersey, 517 F.3d at 582 (stating that 

‘‘[s]ection 112(n)(1) governs how the 

Administrator decides whether to list 

EGUs. * * *’’). As we noted in the 

preamble to the proposed rule, D.C. 

Circuit precedent requires the Agency to 

regulate all HAP from major sources of 

HAP emissions once a source category 

is added to the list of categories under 

CAA section 112(c). National Lime 

Ass’n v. EPA, 233 F.3d 625, 633 (D.C. 

Cir. 2000). 76 FR 24989. 

The commenter does not explain its 

issues with our interpretation of how 

regulation under section 112 works—i.e. 

making a determination that a source 

category should be listed under CAA 

section 112(c), listing the source 

category under CAA section 112(c), 

regulating the source category under 

CAA section 112(d), and conducting the 

residual risk review for sources subject 

to MACT standards pursuant to CAA 

section 112(f). Instead, it asserts that our 

decision is flawed because the 

interpretation we provided does not 

account for all the alternatives for 

regulating EGUs under section 112, and 

that we have not properly exercised our 

discretion leading to a fatal flaw in our 

rulemaking. 

The commenter also ignores the 

language of section 112(n)(1)(A). As 

explained in the proposed rule, the use 

of the terms section, subsection, and 

subparagraph in section 112(n)(1)(A) 

demonstrates that Congress was 

consciously distinguishing the various 

provisions of section 112 in directing 

EPA’s action under section 112(n)(1)(A). 

Congress directed the Agency to 

regulate utilities ‘‘under this section,’’ 

not ‘‘under this subparagraph,’’ and 

accordingly EGUs should be regulated 

under section 112 in the same manner 

as other categories for which the statute 

requires regulation. Furthermore, the 

D.C. Circuit Court found that section 

112(n)(1) ‘‘governs how the 

Administrator decides whether to list 

EGUs’’ and that once listed, EGUs are 

subject to the requirements of section 

112. New Jersey, 517 F.3d at 583. 

Indeed, the D.C. Circuit Court expressly 

noted that ‘‘where Congress wished to 

exempt EGUs from specific 

requirements of section 112, it said so 

explicitly,’’ noting that ‘‘section 

112(c)(6) expressly exempts EGUs from 

the strict deadlines imposed on other 

sources of certain pollutants.’’ Id. 

Congress did not exempt EGUs from the 

other requirements of section 112, and 

once listed, the EPA is reasonably 

regulating EGUs pursuant to the 

standard-setting provisions in section 

112(d), as it does for all other listed 

source categories. 

The commenter provided no 

alternative theory for regulating EGUs 

under CAA section 112, other than to 

state that the EPA could regulate under 

CAA section 112(n)(1). However, even 

assuming for the sake of argument, that 

we could issue standards pursuant to 

CAA section 112(n)(1), we would 

decline to do because there is nothing 

in section 112(n)(1)(A) that provides any 

guidance as to how such standards 

should be developed. Any mechanism 

we devised, absent explicit statutory 

support, would likely receive less 

deference than a CAA section 112(d) 

standard issued in the same manner in 

which the Agency issues standards for 

other listed source categories. We would 

also decline to establish standards 

under section 112(n)(1) because 

Congress did provide a mechanism 

under CAA sections 112(d) and (f) for 

establishing emission standards for HAP 

emissions from stationary sources and it 

is reasonable to use that mechanism to 

regulate HAP emissions from EGUs. 

e. Considering Costs in Finding 

Comment: Several commenters assert 

that the EPA must consider costs in 

assessing whether regulation of EGUs is 

appropriate under CAA section 

112(n)(1)(A). Commenters posit that the 

EPA’s position that ‘‘the term 

‘appropriate’ * * * does not allow for 

the consideration of costs in assessing 

whether hazards * * * are reasonably 

anticipated to occur based on EGU 

emissions,’’ 76 FR at 24,989/1, does not 

withstand scrutiny. According to the 

commenters, the treatment of ‘‘costs’’ 

under section 112(c) does not support 

the Agency’s position, and the process 

by which sources may be ‘‘delisted’’ 

under section 112(c)(9), including no 

consideration of costs, sheds no light on 

the circumstances under which it may 

be ‘‘appropriate’’ to regulate EGUs 

under section 112(n)(1)(A). 

Commenters characterize as 

‘‘unintelligible’’ the EPA’s position that 

it is ‘‘reasonable to conclude that costs 

may not be considered in determining 

whether to regulate EGUs’’ when 

‘‘hazards to public health and the 

environmental are at issue (citing 76 FR 

at 24989). ‘‘Two commenters stated that 

a natural reading of the term 

‘‘appropriate’’ would include the 

consideration of costs. According to the 

commenters, something may be found to 

be ‘‘appropriate’’ where it is ‘‘specially 

suitable,’’ ‘‘fit,’’ or ‘‘proper.’’ See 

Webster’s Third New International 

Dictionary at 106 (1993). The term 

‘‘appropriate’’ carries with it the 

connotation of something that is 

‘‘suitable or proper in the 

circumstances.’’ See New Oxford 

American Dictionary (2d Ed. 2005). 

Considering the costs associated with 

undertaking a particular action is 

inextricably linked with any 

determination as to whether that action 

is ‘‘specially suitable’’ or ‘‘proper in the 

circumstances.’’ One commenter notes 

that in 2005 (70 FR 15994, 16000; March 

29, 2005) the EPA used the dictionary 

definition of ‘‘appropriate,’’ as being 

‘‘especially suitable or compatible’’ and 

that it would be difficult to fathom how 

a regulatory program could be either 

‘‘suitable’’ or ‘‘compatible’’ for a given 

public health objective without 

consideration of cost. 

One commenter asserts that on the 

face of CAA section 112(n)(1)(A), it is 

clear that the EPA is expected to 

consider costs. According to the 

commenter, that Congress intended that 

the EPA investigate and consider 

‘‘alternative control strategies’’ for 

emissions as part of the section 112 

(n)(1) Utility Study when making the 

‘‘appropriate and necessary’’ 

determination refutes the notion that the 

Agency can, and indeed must, disregard 

the cost of regulation in making that 

determination, because the cost of a 

given emission ‘‘control strategy’’ is a 

central factor in any evaluation of 

‘‘alternative’’ controls. 

Further, according to commenters, it 

is well-settled that CAA regulatory 

provisions should be read with a 

presumption in favor of considering 

costs (citing Michigan v. EPA, 213 F.3d 

663, 678 (D.C. Cir. 2000)), and the 

legislative history of section 

112(n)(1)(A) confirms that Congress 

intended EPA to consider costs (citing 

Oxley Statement at 1417). 

Commenters also assert that the EPA 

falsely represents that it ‘‘did not 

consider costs when making the 

‘‘appropriate’’ determination in the 

EPA’s December 2000 notice (76 FR at 

24,989/2). 

Response: The commenters first take 

issue with EPA’s explanation of why the 

Agency determined that costs should 

not be considered in making the 

appropriate determination. What 


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61 76 FR 24990. 

commenters do not identify is an 

express statutory requirement that the 

Agency consider costs in making the 

appropriate determination. Congress 

treated the regulation of HAP emissions 

differently in the 1990 CAA 

amendments because the Agency was 

not acting quickly enough to address 

these air pollutants with the potential to 

adversely affect human health and the 

environment. See New Jersey, 517 F.3d 

at 578. Specifically, following the 1990 

CAA amendments, the CAA required 

the Agency to list source categories and 

nothing in the statute required us to 

consider costs in those listing decision, 

and we have not done so when listing 

other source categories. Thus, it is 

reasonable to make the listing decision, 

including the appropriate 

determination, without considering 

costs. 

The commenters next argue that the 

Agency is compelled by the statute to 

consider costs based on a dictionary 

definition of ‘‘appropriate’’ and the CAA 

section 112(n)(1)(A) direction to 

consider alternative control strategies 

for regulating HAP emissions in the 

Utility Study. 

Concerning the definition of 

‘‘appropriate’’, commenters stated: 

Not only is it ‘‘reasonable’’ for EPA to 

consider costs in determining whether it is 

‘‘appropriate’’ to regulate EGU HAP 

emissions, a natural reading of the term 

indicates that excluding the consideration of 

costs would be entirely unreasonable. 

Something may be found to be ‘‘appropriate’’ 

where it is ‘‘specially suitable,’’ ‘‘fit,’’ or 

‘‘proper.’’ See Webster’s Third New 

International Dictionary at 106 (1993). The 

term ‘‘appropriate’’ carries with it the 

connotation of something that is ‘‘suitable or 

proper in the circumstances.’’ See New 

Oxford American Dictionary (2d Ed. 2005) at 

76. Considering the costs associated with 

undertaking a particular action is 

inextricably linked with any determination 

as to whether that action is ‘‘specially 

suitable’’ or ‘‘proper in the circumstances.’’ 

The EPA believes the definition of 

‘‘appropriate’’ that the commenters 

provide wholly support its 

interpretation and nothing about the 

definition compels a consideration of 

costs. It is appropriate to regulate EGUs 

under CAA section 112 because EPA 

has determined that HAP emissions 

from EGUs pose hazards to public 

health and the environment, and section 

112 is ‘‘specially suitable’’ for regulating 

HAP emissions, and Congress 

specifically designated CAA section 112 

as the ‘‘proper’’ authority for regulating 

HAP emissions from stationary sources, 

including EGUs. Section 112 of the CAA 

is ‘‘suitable [and] proper in the 

circumstances’’ because EPA has 

identified a hazard to public health and 

the environment from HAP emissions 

from EGUs and Congress directed the 

Agency to regulate HAP emissions from 

EGUs under that provision if we make 

such a finding. Cost does not have to be 

read into the definition of ‘‘appropriate’’ 

as commenter suggests. In addition, as 

stated elsewhere in response to 

comments, the Agency does not 

consider costs in any listing or delisting 

determinations, and the EPA maintains 

that it is reasonable to assess whether to 

list EGUs (i.e. the appropriate and 

necessary finding) without considering 

costs. 

The commenters’ argument that costs 

must be considered based on the CAA 

section 112(n)(1)(A) requirement to 

‘‘develop and describe alternative 

control strategies’’ in the Utility Study 

is equally flawed. The argument is 

flawed because Congress did not direct 

the Agency to consider in the Utility 

Study the costs of the controls when 

evaluating the alternative control 

strategies. In addition, the EPA did not 

consider the costs of the alternative 

controls in the Utility Study, as implied 

by the commenter. Thus, even viewing 

section 112(n)(1)(A) in isolation, there is 

nothing in that section that compels 

EPA to consider costs. For the reasons 

described herein, we do not believe that 

it is appropriate to consider costs in 

determining whether to regulate EGUs 

under section 112. 

Additionally, one commenter 

attempts to refute EPA’s statement in 

the preamble to the proposed rule that 

the EPA did not consider costs in the 

2000 finding by pointing to the only two 

mentions of cost in that notice. 

However, the EPA did not say that costs 

were not mentioned in the 2000 finding 

and a review of the regulatory finding 

will show that costs were not 

considered in the regulatory finding. 65 

FR 79830 (December 20, 2000) (‘‘Section 

III. What is EPA’s Regulatory 

Finding?’’). 

f. Considering Requirements of the CAA 

in ‘‘Necessary’’ 

Comment: Several commenters 

disagree with EPA’s position that it 

need consider ‘‘only those requirements 

that Congress directly imposed on EGUs 

through the CAA as amended in 1990,’’ 

for which ‘‘EPA could reasonably 

predict HAP emission reductions at the 

time of the Utility Study.’’ According to 

the commenters, the statutory language 

of CAA section 112(n)(1) requires that 

the EPA consider the scope and effect of 

EGU HAP emissions after the 

imposition of all of the ‘‘requirements’’ 

of the CAA, not just the Acid Rain 

program. The commenter maintains that 

it would have been easy enough for 

Congress in subparagraph 112(n)(1)(A) 

to specify ‘‘after imposition of the 

requirements of Title IV of this 

chapter,’’ but Congress did not. The 

commenters further add that the 

legislative history confirms that 

Congress meant something much 

broader than that, providing that the 

EPA is authorized to regulate EGUs 

under CAA section 112 only after 

‘‘taking into account compliance with 

all provisions of the act and any other 

Federal, State, or local regulation and 

voluntary emission reductions.’’ The 

commenters stated that the CAA’s 

‘‘requirements’’ include the submission 

by states of ozone and fine PM 

attainment demonstrations, as well as 

SIP provisions needed to reach 

attainment of the NAAQS because such 

provisions could include controls on 

EGUs to reduce SO2 and NOX, which 

controls could also result in a reduction 

in Hg emissions. 

Response: The commenter’s 

characterization of the facts is flawed 

and its reliance on legislative history 

that is in direct conflict with the express 

terms of the statute is unpersuasive. 

On the facts, the EPA explained in the 

preamble to the proposed rule its 

interpretation of the phrase ‘‘after 

imposition of the requirements of [the 

Act]’’ as it related to the conduct of the 

Utility Study.61 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, the EPA 

ultimately determined that it could not 

sufficiently quantify the reductions that 

might be attributable to the NAAQS 

because states are tasked with 

implementing those standards. See 

Utility Study, pages ES–25, 1–3, 2–32. 

Conversely, commenter’s position is 

that the EPA must consider 

implementation of all the requirements 

of the CAA, but it does not indicate how 

in conducting the Utility Study the 

Agency could have possibly considered 

co-benefit HAP reductions attributable 

to all future CAA requirements. The 

Agency appropriately considered the 

other requirements of the Act in the 

Utility Study and considered those 

requirements in determining that it was 


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62 76 FR 24990. 

necessary to regulate coal- and oil-fired 

EGUs in December 2000. 

Although not required, the Agency in 

the preamble to the proposed rule 

conducted further analyses in support of 

the 2000 finding. In doing so, we 

considered a number of requirements 

that far exceed what Congress 

contemplated when enacting CAA 

section 112(n)(1)(A)), and our analyses 

still show that it remains necessary to 

regulate coal- and oil-fired EGUs under 

section 112. 76 FR 24991. 

We maintain that we have reasonably 

interpreted the requirement to consider 

the hazards to public health and the 

environment reasonably anticipated to 

occur after imposition of the 

requirements of the Act as explained in 

the preamble to the proposed rule.62 In 

addition, as stated above, we also 

believe it would be reasonable to find it 

necessary to regulate HAP emissions 

from EGUs based on our finding that 

such emissions pose a hazard to public 

health and the environment today 

without considering future reductions 

that we currently project to occur as the 

result of imposition of CAA 

requirements that are not yet effective 

(e.g., CSAPR). 

Moreover, Representative Oxley’s 

statement cited by the commenter is not 

consistent with the express terms of 

CAA section 112(n)(1)(A) on this issue. 

Representative Oxley stated that the 

EPA was to take ‘‘into account 

compliance with all the provisions of 

the act and any other Federal, State, or 

local regulation and voluntary emission 

reductions,’’ but CAA section 

112(n)(1)(A) directs the Agency to 

consider ‘‘imposition of the 

requirements of this chapter,’’ which 

means the CAA. The Agency reasonably 

focused on the requirements of the 

Clean Air Act, which are federally 

enforceable, and declined to include 

potential future reductions that may be 

attributable to voluntary emission 

reduction programs or state and local 

regulations that have no basis in the 

Clean Air Act and are not federally 

enforceable. In addition to the statutory 

direction not to consider such 

requirements, the EPA believes it is 

reasonable not to include potential 

reductions attributable to such 

requirements because the Agency 

cannot assure that such requirements 

and the attendant HAP reductions will 

remain absent regulation under section 

112. Finally, the commenter implies 

that EPA’s position is that the Agency 

will only consider requirements of the 

Act that directly regulate HAP 

emissions. The EPA never stated or 

suggested that interpretation and a fair 

reading of the proposed rule will 

demonstrate that EPA considered 

requirements that achieve co-benefit 

HAP emission reductions, for example 

the Transport Rule (known as CSAPR). 

Comment: One commenter stated that, 

under CAA section 112, regulating 

EGUs is permissible only insofar as it is 

focused, targeted, and predicated on 

concrete findings by the Agency that 

such regulation is indeed ‘‘necessary.’’ 

According to the commenter, the EPA 

construes CAA section 112(n)(1)(A) as 

permitting it to find that it is 

‘‘necessary’’ to regulate EGUs even 

where the Agency does not actually 

know whether it is ‘‘necessary’’ to 

regulate EGUs. Citing the D.C. Circuit, 

the EPA suggests that ‘‘‘there are many 

situations in which the use of the word 

‘necessary,’ in context, means 

something that is done, regardless of 

whether it is indispensible,’’’ in order to 

‘‘‘achieve a particular end.’’’ 76 FR 

24990, quoting Cellular 

Telecommunications v. FCC, 330 F.3d 

502, 510 (D.C. Cir. 2003). The 

commenter stated that in the ‘‘context’’ 

of CAA section 112(n)(1)(A), as 

informed by the relevant legislative 

history from Representative Oxley, it is 

clear that regulation of EGU HAP 

emissions can be considered 

‘‘necessary’’ only if EPA were to 

‘‘clearly establish’’ that such regulation 

was effectively ‘‘indispensible’’ to 

address the identified harm. As EPA 

concedes that it has made no such 

determination here, its proposal is 

fatally flawed for that reason alone. 

The commenter further asserts that 

the EPA erred when it concluded that it 

may ‘‘ ‘determine it is necessary to 

regulate under section 112’ when the 

Agency is ‘uncertain whether 

imposition of the requirements of the 

CAA will address the identified 

hazards’’’ (citing 76 FR at 24,991/3). 

According to the commenter, the EPA 

‘‘cannot take refuge in its own 

‘uncertainty’ to support a finding that it 

is ‘necessary’ to regulate EGUs under 

section 112, and the Act precludes the 

EPA from ‘‘‘err[ing] on the side of 

regulation’’’ in face of uncertainty (id.). 

The commenter also implies that the 

finding was based on non-HAP 

emissions. 

Response: The commenter again relies 

on the legislative statements of one 

Representative and asserts that the 

statements are controlling. The EPA 

disagrees with commenter and 

maintains that its interpretation of the 

term ‘‘necessary’’ is reasonable. 76 FR 

24990–92 (Section III.A.2.b of the 

preamble to the proposed rule contains 

the EPA’s interpretation of the term 

‘‘necessary’’.) 76 FR 24990–92 (Section 

III.A.2.b of the proposed rule contains 

EPA’s interpretation of the term 

‘‘necessary’’.) The commenter also, in a 

footnote, implies that EPA based the 

appropriate and necessary finding on 

non-HAP air pollution. The commenter 

is wrong as explained in more detail 

above. 

As an initial matter, this comment is 

only addressing one aspect of the 

Agency’s interpretation of the term 

necessary. As EPA stated at proposal: 

If we determine that the imposition of the 

requirements of the CAA will not address the 

identified hazards, EPA must find it 

necessary to regulate EGUs under section 

112. Section 112 is the authority Congress 

provided to address hazards to public health 

and the environment posed by HAP 

emissions and section 112(n)(1)(A) requires 

the Agency to regulate under section 112 if 

we find regulation is ‘‘appropriate and 

necessary.’’ If we conclude that HAP 

emissions from EGUs pose a hazard today, 

such that it is appropriate, and we further 

conclude based on our scientific and 

technical expertise that the identified 

hazards will not be resolved through 

imposition of the requirements of the CAA, 

we believe there is no justification in the 

statute to conclude that it is not necessary to 

regulate EGUs under section 112. 

76 FR 24991. 

The EPA has determined that the 

imposition of the requirements of the 

CAA will not address the hazards to 

public health or hazards to the 

environment that EPA has identified; 

therefore, it is necessary to regulate 

EGUs under CAA section 112. 

The EPA further interpreted the 

statute to allow the Agency to find that 

it is necessary to regulate EGUs under 

other circumstances, and it is with one 

of our additional interpretations that 

commenter takes issue. Specifically, the 

commenter argues that EPA’s 

interpretation authorizes the Agency to 

find it necessary to regulate EGUs when 

we are uncertain it is necessary, but that 

misconstrues our interpretation and the 

record. At proposal, the EPA stated: 

In addition, we may determine it is 

necessary to regulate under section 112 even 

if we are uncertain whether the imposition of 

the requirements of the CAA will address the 

identified hazards. Congress left it to EPA to 

determine whether regulation of EGUs under 

section 112 is necessary. We believe it is 

reasonable to err on the side of regulation of 

such highly toxic pollutants in the face of 

uncertainty. Further, if we are unsure 

whether the other requirements of the CAA 

will address an identified hazard, it is 

reasonable to exercise our discretion in a 

manner that assures adequate protection of 

public health and the environment. 

Moreover, we must be particularly mindful of 

CAA regulations we include in our modeled 

estimates of future emissions if they are not 


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final or are still subject to judicial review 

([e.g.], the Transport Rule). If such rules are 

either not finalized or upheld by the Courts, 

the level of risk would potentially increase. 

Id. 

The CAA requires EPA to exercise its 

discretion in determining whether 

regulation under section 112 is 

necessary, and the D.C. Circuit has 

stated that ‘‘there are many situations in 

which the use of the word ‘necessary,’ 

in context, means something that is 

done, regardless of whether it is 

indispensible, to achieve a particular 

end.’’ See Cellular Telecommunications 

& Internet Association, et al. v. FCC, 330 

F.3d 502, 510 (D.C. Cir. 2003). The 

EPA’s interpretation of ‘‘necessary’’ is 

reasonable in the context of CAA 

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

The commenter stated that EPA 

concedes that the Agency has not 

‘‘clearly established’’ that regulation of 

HAP emissions under CAA section 112 

is ‘‘indispensible.’’ The EPA has 

conceded nothing but, more 

importantly, the supposed standard that 

the commenter presents for evaluating 

whether it is necessary to regulate HAP 

emissions from EGUs is not required by 

the statute. Even the limited legislative 

history on which the commenter 

incorrectly relies does not espouse such 

a standard. The commenter specifically 

takes issue with EPA’s statement that 

the Agency may find it is necessary to 

regulate EGUs under CAA section 112 if 

we are ‘‘uncertain whether imposition 

of the other requirements of the CAA 

will sufficiently address the identified 

hazards.’’ 76 FR at 24990. The 

commenter has again misinterpreted the 

Agency’s position by stating that ‘‘EPA 

construes CAA section 112(n)(1)(A) as 

permitting it to find that it is 

‘‘necessary’’ to regulate EGUs even 

where the Agency does not actually 

know whether it is ‘‘necessary’’ to 

regulate EGUs.’’ Instead, the EPA 

maintains that it may be necessary to 

regulate EGUs under CAA section 112 if 

we identify a hazard to public health or 

the environment that is appropriate to 

regulate today and our projections into 

the future do not clearly establish that 

the imposition of the requirements of 

the CAA will address the identified 

hazard in the future. Making a 

prediction about future emission 

reductions from a source category is 

difficult for statutory provisions that do 

not mandate direct control of the given 

source category or pollutants of concern. 

We maintain that erring on the side of 

caution is appropriate when the 

protection of public health and the 

environment from HAP emissions is not 

assured based on our modeling of future 

emissions. 

Furthermore, as we stated in the 

preamble to the proposed rule, we 

believe it would be reasonable to find it 

appropriate and necessary to regulate 

EGUs under section 112 today based on 

a determination that HAP emissions 

from EGUs pose a hazard to public 

health and the environment without 

considering future HAP emission 

reductions. 76 FR 24991, n.14. We 

maintain this is reasonable because 

‘‘Congress could not have contemplated 

in 1990 that EPA would have failed in 

2011 to have regulated HAP emissions 

from EGU’s where hazards to public 

health and the environment remain.’’ Id. 

The phrase ‘‘after imposition of the 

requirements of [the Act]’’ as 

contemplated CAA section 112(n)(1)(A) 

could be read to apply only to those 

requirements clearly and directly 

applicable to EGUs under the 1990 CAA 

amendments, all of which have been 

implemented and still hazards to public 

health and the environment from HAP 

emissions from EGUs remain. 

g. Listing EGUs Under 112 

Comment: One commenter stated that 

even if EPA were to establish under 

CAA section 112(n)(1)(A) that it is 

‘‘appropriate and necessary’’ to regulate 

HAP emissions from EGUs, regulating 

those emissions in the form of a MACT 

standard established pursuant to CAA 

section 112(d) is contrary to the plain 

language of the Act. According to the 

commenter, if EPA proceeds to finalize 

the proposal and adopts such a 

standard, the rule will for this reason 

alone be ‘‘dead-on-arrival’’. According 

to the commenter, the EPA apparently 

believes that its only option in 

regulating EGU HAP emissions is 

establishing a MACT standard under 

CAA section 112(d). In the preamble to 

its proposal, the commenter states that 

EPA contends that, ‘‘once the 

appropriate and necessary finding is 

made,’’ EGUs are then ‘‘subject to 

section 112 in the same manner as other 

sources of HAP emissions’’—i.e., by 

‘‘listing’’ EGUs under CAA section 

112(c) and adopting a MACT standard 

under CAA section 112(d). See 76 FR 

24993/2 (emphasis added). The 

commenter further stated that, given 

that Congress ‘‘directed the Agency to 

regulate utilities ‘under this section’ 

[i.e., CAA section 112],’’ EPA continues, 

it follows that ‘‘EGUs should be 

regulated in the same manner as other 

categories for which the statute requires 

regulation.’’ Id. (emphasis added). The 

commenter asserts that as EPA sees it, 

because ‘‘Congress did not exempt EGUs 

from the other requirements of section 

112,’’ once EGUs were ‘‘listed’’ under 

CAA section 112(c), the Agency was 

‘‘required to establish emission 

standards for EGUs consistent with the 

requirements set forth in section 

112(d).’’ Id. at 24,993/3 (emphasis 

added). 

The commenter stated that, in support 

of this reading of the CAA, the EPA 

invokes the decision of the U.S. Court 

of Appeals for the D.C. Circuit in New 

Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 

2008). The commenter further alleged 

that, according to EPA, the D.C. Circuit 

has ‘‘already held that section 112(n)(1) 

‘governs how the Administrator decides 

whether to list EGUs.’ ’’ See 76 FR 

24993/2–3, quoting 517 F.3d at 583. The 

commenter stated that EPA construes 

that holding as indicating that, ‘‘once 

listed, EGUs are subject to the 

requirements of section 112’’— 

including, the EPA presumes, CAA 

section 112(d). Id. The commenter 

stated that elsewhere, the EPA construes 

CAA section 112(n)(1) (A) as 

‘‘govern[ing] how the Administrator 

decides whether to list EGUs for 

regulation under section 112,’’ and 

quotes the D.C. Circuit’s observation in 

New Jersey that ‘‘Section 112(n)(1) 

governs how the Administrator decides 

whether to list EGUs; it says nothing 

about delisting EGUs.’’ See 76 FR 

24981/2, quoting 517 F.2d at 582. 

The commenter asserts that EPA 

misinterprets the ‘‘under this section’’ 

language of CAA section 112(n)(1); 

overstates the significance of the New 

Jersey decision; and, as a consequence, 

misapprehends the scope of its own 

discretion to formulate regulatory 

standards for EGUs under CAA section 

112. In light of these errors, the 

commenter maintains that EPA should 

withdraw the proposed MACT rule. 

One commenter stated that if 

Congress had intended that EPA 

regulate EGU HAP emissions only 

through a MACT standard, Congress 

could have—and presumably would 

have—directed the Agency to regulate 

EGU emissions ‘‘under CAA section 

112(d).’’ Thus, the commenter 

maintained that EPA’s authority to 

regulate EGU HAP emissions is not 

derived from any particular subsection 

of CAA section 112. Rather, the 

commenter stated that EPA is 

authorized to regulate ‘‘under this 

section’’—i.e., CAA section 112 

generally—as may be ‘‘appropriate and 

necessary.’’ The commenter stated that 

there is nothing on the face of CAA 

section 112(n)(1)(A) that specifies that 

regulation of EGUs must occur under 

CAA section 112(d). To the contrary, 

according to the commenter, a plain 

reading of CAA section 112(n)(1)(A), as 

interpreted based on the Oxley 

statement, indicates that establishing a 


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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 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. 

We maintain that our interpretation of 

the statute gives meaning to all the 

words, and the commenter’s 

interpretation does not give any 

particular meaning to the requirement to 

‘‘regulate under this section [112]’’. The 

commenter is correct that Congress 

could have in CAA section 112(n)(1)(A) 

directed EPA to regulate HAP from 

EGUs under CAA section 112(d) after 

making the appropriate and necessary 

finding, but the commenter presumes 

too much when it stated that Congress 

would have directed the Agency to 

regulate HAP emissions from EGUs in 

such a manner if that is what Congress 

wanted, simply by including the phrase 

‘‘regulate under this paragraph’’ or 

‘‘regulate under this subparagraph’’ 

instead of directing the Agency to 

‘‘regulate under this section’’. It did not 

do so. 

As we explained in the section II.A. 

of the proposed rule, CAA section 112 

establishes a mechanism to list and 

regulate stationary sources of HAP 

emissions. 76 FR 24980–81. Regulation 

under CAA section 112 generally 

requires listing under CAA section 

112(c), regulation under CAA section 

112(d), and, for sources subjected to 

MACT standards, residual risk 

regulations under CAA section 112(f) (as 

necessary to protect human health and 

the environment with an ample margin 

of safety). A determination that EGUs 

should be listed once the prerequisite 

appropriate and necessary finding is 

made is wholly consistent with the 

language of section 112(n)(1)(A), and 

listed sources must be regulated under 

CAA section 112(d). See CAA section 

112(c)(2); see also New Jersey, 517 F.3d 

at 583 (112(n)(1)(A) ‘‘governs how the 

Administrator decides whether to list 

EGUs’’). 

As noted above, Congress used the 

terms section, subsection, and 

subparagraph in section 112(n)(1)(A). 

The use of these three terms 

demonstrates that Congress was 

consciously distinguishing between the 

various provisions of section 112. 

Congress directed the Agency to 

regulate utilities ‘‘under this section,’’ 

and accordingly EGUs should be 

regulated in the same manner as other 

categories for which the statute requires 

regulation. 

Furthermore, the flaws in the 

commenter’s interpretation are 

highlighted by other CAA section 112 

provisions wherein Congress provided 

specific direction as to the manner of 

regulation. For example, CAA section 

112(m)(6) requires the Administrator to 

determine ‘‘whether the other 

provisions of this section [112] are 

adequate’’ and also indicates that ‘‘[a]ny 

requirements promulgated pursuant to 

this paragraph * * * shall only apply 

to the coastal waters of the States which 

are subject to [section 328 of the CAA].’’ 

(emphasis added). 

In addition, CAA section 112(n)(3) 

provides that when the Agency is 

‘‘promulgating any standard under this 

section [112] applicable to publicly 

owned treatment works, the 

Administrator may provide for control 

measures that include pretreatment of 

discharges causing emissions of 

hazardous air pollutants and process or 

product substitutions or limitations that 

may be effective in reducing such 

emissions.’’ Finally, CAA section 

112(n)(5) directs the Agency to assess 

hydrogen sulfide emissions from oil and 

gas extraction and ‘‘develop and 

implement a control strategy for 

emissions of hydrogen sulfide to protect 

human health and the environment 

* * * using authorities under [the CAA] 

including [section 111] of this title and 

this section [112].’’ (emphasis added). 

We believe these provisions provide 

ample evidence that Congress knew 

how to alter or caveat regulation under 

CAA section 112 when that was its 

intent. For these reasons, we believe 

commenter’s argument is without merit. 

Comment: Two commenters stated 

that CAA section 112(n)(1)(A) does not 

specify that regulation of EGUs must 

proceed under CAA section 112(d). 

According to the commenter, an 

argument could be made, therefore, that 

the CAA accords EPA with the 

discretion to regulate EGUs using 

strategies other than emission standards 

in CAA section 112(d). The commenters 

also state that section 112(n)(1)(A) of the 

CAA requires that EPA ‘‘develop and 

describe’’ alternative control strategies 

for emissions which may warrant 

regulation under CAA section 112. 

According to the commenters if 

Congress meant for EPA to have one 

sole regulatory option, i.e., regulation of 

EGUs only under CAA section 112(d), 

then the development of alternative 

control strategies would be rendered 

meaningless because under CAA section 

112(d)(3), the EPA is required to 

determine the level of control that is 

achieved by the best performing existing 

units for which it has data and then to 

impose that level of control on all 

existing units. The commenter further 

states that the development of 

‘‘alternative control strategies’’ has no 

role to play in this process. One 

commenter does note that the 

consideration of ‘‘alternative’’ controls 

becomes relevant, if at all, only in those 

circumstances where EPA might seek to 

establish a ‘‘Beyond-the-Floor’’ MACT 

standard pursuant to CAA section 

112(d)(2). 


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Response: The commenters are correct 

that CAA section 112(n)(1)(A) directed 

the Agency to develop and describe in 

the Utility Study report to Congress 

alternative control strategies for HAP 

emissions from EGUs that may warrant 

regulation in the Utility Study, but the 

commenters’ interpretation of and 

conclusion based on that language are 

both factually and legally inaccurate. 

The commenters appear to interpret 

the word ‘‘alternative control strategies’’ 

to mean something other than the 

traditional control technologies and 

control measures that are used to 

control HAP emissions from EGUs. We 

do not believe that is a reasonable 

interpretation of the statute, and the 

Agency did not interpret the statute in 

that manner when it conducted the 

Utility Study. In Chapter 13 of the 

Utility Study, the EPA considered a 

range of control measures that would 

reduce the different types of HAP 

emitted from EGUs. http:// 

www.epa.gov/ttn/atw/combust/utiltox/ 

eurtc1.pdf. The EPA considered precombustion controls such as coal 

washing, fuel switching, and 

gasification; combustion controls such 

as boiler design; post-combustion 

controls such as fabric filters, scrubbers, 

and carbon absorption; and alternative 

controls strategies such as demand-side 

management, energy conservation, and 

use of alternative fuels (e.g., biomass) or 

renewable energy. The options 

discussed in the Utility Study for 

controlling HAP emissions from EGUs 

are almost universally available to 

comply with a CAA section 112(d) 

standard. 

Given the manner in which the 

Agency conducted the Utility Study, the 

EPA interpreted the statutory direction 

as a requirement to set forth the 

potential alternative control options 

available to EGUs to comply with CAA 

section 112 standards in the event the 

Agency determined regulation under 

section 112 was appropriate and 

necessary. The EPA’s development and 

discussion in the Utility Study of 

alternative control strategies for 

complying with the standards would 

help prepare EGUs to comply with the 

standards if promulgated. Thus, the EPA 

interpreted the direction to address 

control strategies in the Utility Study as 

a request to identify the controls 

available to EGUs for addressing HAP 

emissions, and such information would, 

of course, be relevant if EPA determined 

that such emissions warranted 

regulation under section 112. 

Furthermore, the EPA establishes 

CAA section 112(d) standards for 

stationary sources and it is the 

responsibility of the sources to comply 

with the standards using any 

mechanism available, including precombustion 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 as the Agency 

considers relevant technologies and 

HAP emission reduction approaches in 

evaluating whether to set a more 

stringent beyond the floor standard. 

Comment: One commenter points to 

CAA section 307(d)(1)(C) and notes that 

CAA section 112(n) is listed among the 

provision for which the rulemaking 

requirements of CAA 307(d) apply. 

Commenter maintains that this 

inclusion creates an expectation under 

the statute that EPA may establish 

regulatory standards under CAA 112(n). 

The commenter points to CAA sections 

112 (n)(1), (n)(3), and (n)(5) and states 

that those provisions specifically 

discuss regulation under CAA section 

112 and that EPA must explain why 

CAA 307(d)(1)(C) states ‘‘any regulation 

under’’ CAA 112(n) to defend regulation 

of utilities under section 112(d). The 

commenter then implies that EPA erred 

by not even mentioning this provision at 

proposal. 

The commenter also takes issue with 

EPA’s statement in the proposed rule 

that ‘‘use of the terms section, 

subsection, and subparagraph’’ 

‘‘demonstrates that Congress was 

consciously distinguishing the various 

provisions of section 112 in directing 

the conduct of the study and the manner 

in which the Agency must regulate 

EGUs,’’ if EPA determines that it is 

appropriate and necessary to regulate 

EGUs. See 76 FR at 24,993/2. 

One commenter does not agree with 

the EPA’s finding that the word 

‘‘subsection’’ in the first sentence of 

CAA section 112(n)(1)(A) demonstrates 

that Congress was consciously 

distinguishing between the various 

provisions of CAA section 112 in 

directing the conduct of the study and 

the manner in which the Agency must 

regulate EGUs,’’ were the EPA to ‘‘find[ ] 

it appropriate and necessary to do so.’’ 

See 76 FR 24993/2. According to the 

commenter, the only evident reason that 

the word ‘‘subsection’’ is used in the 

first sentence of CAA section 

112(n)(1)(A) is because the reference is 

made to the ‘‘pollutants’’ which the 

Utility Study is to address—i.e., the 

‘‘pollutants’’ that are emitted by EGUs 

and which are ‘‘listed under subsection 

(b)’’ of CAA section 112. Similarly, the 

word ‘‘subparagraph’’ is used in the last 

sentence of CAA section 112(n)(1)(A) to 

identify ‘‘the study’’ which the EPA is 

directed to undertake by subparagraph 

(A) of CAA section 112(n)(1)—i.e., the 

Utility Study. That the last sentence of 

subparagraph (n)(1)(A) also states that 

EPA ‘‘shall regulate electric utility 

steam generating units under this 

section’’ does not even imply—much 

less expressly communicate—that 

regulation ‘‘under this section’’ must 

mean ‘‘regulation under section 112(d).’’ 

The commenter stated that Congress 

was ‘‘consciously distinguishing’’ 

between the ‘‘various provisions of 

section 112’’ for the sake of clarity in the 

drafting of CAA section 112(n). 

The commenter also asserts that the 

EPA mistakenly relies on section 

112(c)(6) when the EPA states that 

‘‘ ‘where Congress wished to exempt 

EGUs from specific requirements of 

section 112, it said so explicitly. 

Congress did not exempt EGUs from the 

other requirements of section 112,’ ’’ and 

thus the Agency is ‘‘ ‘required to 

establish emission standards for EGUs 

consistent with the requirements set 

forth in section 112(d)’ ’’ (citing 76 FR 

at 24,993 (internal quotation omitted)). 

According to the commenter, nothing 

in section 112(c)(6) indicates how (or 

even whether) EGU HAP emissions 

should be regulated under section 112; 

paragraph (c)(6) serves only to reiterate 

that the regulation of such emissions is 

to occur (if at all) as is provided by 

section 112(n)(1). The commenter also 

asserts that the EPA mistakenly relies on 

New Jersey. According to the 

commenter, the D.C. Circuit in that case 

did not indicate that the language of 

section 112(c)(6) should, or could, be 

construed to mean that EGUs must be 

regulated under a MACT standard 

adopted pursuant to section 112(d). 

Response: The commenter makes a 

number of arguments that appear to take 

issue with the EPA’s determination that 

EGUs should be regulated under CAA 

section 112(d) if the Agency determines 

that regulation of HAP emissions from 

such units is appropriate and necessary. 


srobinson on DSK4SPTVN1PROD with RULES2
9332 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

63We note that in our January 2004 proposed 

rule, we solicited comment on whether section 

112(n)(1)(A) provided independent authority to 

regulate EGUs. We received several comments on 

this issue, and we rejected the concept after 

reviewing the comments and further considering 

the language of section 112(n)(1)(A) and the 

structure of section 112. As such, we proposed and 

are finalizing that once the Agency determines that 

it is appropriate and necessary to regulate EGUs 

under section 112, those sources are listed pursuant 

to subsection 112(c), as we did in December 2000, 

and the Agency must set standards for those sources 

pursuant to section 112(d). See section 112(c) and 

(d)(1) (requiring establishment of 112(d) standards 

for listed source categories). 

The commenter implies that the EPA 

erred because alternative mechanisms 

for regulation of EGUs under CAA 

section 112 might exist. We do not 

agree. 

The commenter’s argument that the 

EPA erred because we did not explain 

why section CAA section 307(d)(1)(C) 

contemplates regulations under CAA 

section 112(n) is without merit. It is 

correct that the Agency believes EGUs 

should be regulated in the same manner 

as other sources if the appropriate and 

necessary finding is made because of the 

structure of CAA section 112. Nothing 

in CAA section 112(n)(1) requires or 

implies that the Agency should or must 

establish standards for EGUs under that 

provision. Furthermore, unlike CAA 

sections 112(n)(3) and 112(n)(5) that 

commenter cites, CAA section 

112(n)(1)(A) does not provide any 

guidance concerning the manner in 

which EPA is authorized or required to 

regulate sources under CAA section 112. 

See CAA section 112(n)(3) (specifically 

authorizing identified control measures 

and other requirements for 

consideration in issuing standards 

under CAA section 112); see also CAA 

section 112(n)(5) (directing the Agency 

to develop and implement a control 

strategy for emissions of hydrogen 

sulfide using any authority available 

under the CAA, including sections 112 

and 111, if regulation is appropriate). 

For these reasons, we disagree that any 

error occurred because we did not 

specifically discuss in this proposed 

rule whether we could or should 

regulate EGUs under CAA section 

112(n)(1) instead of CAA section 

112(d).63 The Agency validly listed 

EGUs in 2000 and listed sources must 

be regulated pursuant to CAA section 

112(d). 

Even if we agreed that regulation 

under CAA section 112(n)(1) was a 

viable option for EGUs, we would still 

have listed and regulated EGUs like 

other sources because CAA section 

112(d) provides a statutory framework 

for regulating HAP emissions from 

sources and CAA section 112(n)(1) does 

not. We believe that even if CAA section 

112(n)(1) were available to regulate 

EGUs, there would be sufficient 

uncertainty about the legal vulnerability 

of such an approach to caution against 

employing it. This legal uncertainty 

would be particularly troubling in light 

of the fact that we have identified 

hazards to public health and the 

environment from HAP emissions from 

EGUs that warrant regulation, and these 

regulations are long overdue. 

The commenter also takes issue with 

our statement in the preamble to the 

proposed rule that the use of the words 

‘‘section’’, ‘‘subsection’’, and 

‘‘subparagraph’’ in CAA section 

112(n)(1)(A) ‘‘demonstrates that 

Congress was consciously 

distinguishing the various provisions of 

section 112 in directing the conduct of 

the study and the manner in which the 

Agency must regulate EGUs.’’ See 76 FR 

24993. The commenter appears to make 

much of our use of the word ‘‘must’’ in 

that sentence and also states that our 

interpretation of the significance of the 

use of the three terms in CAA section 

112(n)(1)(A) is flawed because Congress 

only used the three terms for purposes 

of clarity. The commenter is incorrect 

on both points. With respect to the 

commenter’s concern regarding the use 

of the word ‘‘must’’ in the sentence 

quoted above, we note that in the next 

sentence we stated that ‘‘Congress 

directed the Agency to regulate utilities 

‘under this section,’ and accordingly 

EGUs should be regulated in the same 

manner as other categories for which the 

statute requires regulation.’’ Id. 

(emphasis added). We were not 

foreclosing the possibility of any 

alternative interpretation and our use of 

the term ‘‘must’’ should not detract from 

the point we were trying to make. 

Specifically, we believe that Congress 

would have directed us to regulate 

EGUs under CAA section 112(n)(1)(A) if 

that was its intent and, absent that 

mandate, the better reading of the 

statute is the one provided in the 

preamble to the proposed rule, which is 

that EGUs should be listed pursuant to 

CAA section 112(c) and subject to CAA 

section 112(d) emission standards. 

The commenter also stated that the 

EPA relied on CAA section 112(c)(6) to 

support a conclusion that EGUs must be 

regulated under CAA section 112(d). 

The commenter takes the EPA’s 

statements out of context. The statement 

in whole read: 

Furthermore, the D.C. Circuit Court has 

already held that section 112(n)(1) ‘‘governs 

how the Administrator decides whether to 

list EGUs’’ and that once listed, EGUs are 

subject to the requirements of CAA section 

112. New Jersey, 517 F.3d at 583. Indeed, the 

D.C. Circuit Court expressly noted that 

‘‘where Congress wished to exempt EGUs 

from specific requirements of section 112, it 

said so explicitly,’’ noting that ‘‘section 

112(c)(6) expressly exempts EGUs from the 

strict deadlines imposed on other sources of 

certain pollutants.’’ Id. Congress did not 

exempt EGUs from the other requirements of 

CAA section 112, and once listed, EPA is 

required to establish emission standards for 

EGUs consistent with the requirements set 

forth in CAA section 112(d), as described 

below. See 76 FR 24993. 

As can be seen from this passage, the 

Court cited section 112(c)(6) as an 

example of Congress’ intent regarding 

regulating EGUs under CAA section 

112. The commenter cited the last 

clause of the last sentence of the 

paragraph quoted above without 

including the prefatory clause ‘‘once 

listed,’’ and, without that clause, the 

statement is not fairly characterized. 

The point the EPA was making in that 

paragraph is that EGUs are a listed 

source category and listed sources must 

be regulated under CAA section 112(d) 

unless the EPA delists the source 

category. 

Comment: One commenter stated that 

EPA overstates the significance of the 

D.C. Circuit’s holding in New Jersey by 

suggesting that the decision mandates 

EGU regulation under CAA section 

112(d) because EGUs ‘‘remain listed’’ 

under CAA section 112(c), See New 

Jersey, 517 F.3d at 582. According to the 

commenter, the court declined to 

address the lawfulness of EPA’s having 

‘‘listed’’ EGUs under CAA section 

112(c), leaving that matter to be decided 

if and when EPA adopted standards for 

EGUs under CAA section 112. Nowhere 

in the decision did the D.C. Circuit 

indicate that EPA must regulate EGUs 

under CAA section 112(d). 

According to the commenter, the EPA 

must consider both whether the 

regulation of EGUs is ‘‘appropriate and 

necessary’’ under section 112(n)(1) and 

address anew whether the Agency is 

authorized by section 112 to list EGUs 

under section 112(c) at all. The 

commenter asserts that on the face of 

the proposal, the EPA has not revisited 

the question whether the ‘‘listing’’ of 

EGUs under section 112(c) is consistent 

with congressional intent. 

Response: The commenter’s 

arguments are circular and it is difficult 

to fully determine exactly what its issue 

is with EPA’s listing; however, it 

appears that the commenter believes 

that EPA incorrectly relied on the New 

Jersey decision to justify the listing of 

EGUs. The commenter also appears to 

argue that the Agency has never 

explained why it has the authority to 

list EGUs at all. We disagree. 

As stated in the preamble to the 

proposed rule, CAA section 112(n)(1)(A) 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9333 

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 

24998. The only condition precedent to 

regulating EGUs under CAA section 112 

is a finding that such regulation is 

appropriate and necessary (after 

conducting and considering the Utility 

Study), and once that finding is made 

the Agency has the authority to list 

EGUs under CAA section 112(c) as the 

first step in the process of establishing 

regulations under section 112. The D.C. 

Circuit agrees with that interpretation of 

the statute as evidenced by its statement 

in New Jersey that ‘‘section 112(n)(1)(A) 

governs how the Administrator decides 

whether to list EGUs for regulation 

under section 112,’’ 517 F.3d at 582, and 

the Court’s statement directly 

contradicts the commenter’s position. 

The EPA did not rely on the New 

Jersey decision to justify the appropriate 

and necessary finding as the commenter 

suggests. We based the finding in 2000 

on the extensive information available 

to the Agency at the time, and we 

confirmed the finding in the preamble 

to the proposed rule based on new 

information. The commenter had ample 

opportunity to comment on the 

appropriate and necessary finding, and 

it may challenge the basis of the listing 

(i.e. the appropriate and necessary 

finding) when EPA issues the final 

standards. 

Comment: One commenter believes 

that the D.C. Circuit will condemn the 

final rule as a result of EPA’s 

‘‘misapprehension’’ that upon making 

an ‘‘appropriate and necessary’’ finding, 

the Agency is compelled by the CAA to 

adopt a regulatory standard for EGUs 

under CAA section 112(d). According to 

the commenter, a regulation will be 

invalid if the regulation ‘‘ ‘was not based 

on the [agency’s] own judgment’ ’’ but 

‘‘ ‘rather on the unjustified assumption 

that it was Congress’ judgment that such 

[a regulation] is desirable’ or required.’’ 

See Transitional Hospitals Corp. v. 

Shalala, 222 F.3d 1019, 1029 (D.C. Cir. 

2000), quoting Prill v. NLRB, 755 F.2d 

941, 948 (D.C. Cir. 1985). The 

commenter further notes that the D.C. 

Circuit has held that, where an agency 

wrongly construes a judicial decision as 

compelling a particular statutory 

interpretation, and thereby unduly 

limits the scope of its own discretion, 

the agency’s action cannot be sustained. 

See, e.g., Phillips Petroleum Co. v. 

FERC, 792 F.2d 1165, 1171 (D.C. Cir. 

1986). The commenter believes the rule 

is bound to be rejected and that the EPA 

should ‘‘reconsider the legal 

interpretations on which it purports to 

base its rule.’’ 

Response: We do not agree that we 

have improperly interpreted the statute 

as limiting our discretion in the manner 

suggested by the commenter. The 

commenter makes only one specific 

allegation in this comment and that 

concerns the Agency’s conclusion that it 

must establish CAA section 112(d) 

standards for EGUs in light of the New 

Jersey decision. The commenter does 

not explain why that conclusion is 

incorrect. As we state above and in the 

preamble to the proposed rule, because 

EGUs are a CAA section 112(c) listed 

source category, the Agency must 

establish CAA section 112(d) standards 

or delist EGUs pursuant to CAA section 

112(c)(9). See New Jersey, 517 F.3d at 

582–83 (holding that EGUs remain 

listed under section 112(c)); see also 

CAA section 112(c)(2) (requiring the 

Agency to ‘‘establish emission standards 

under subsection [112] (d)’’ for listed 

source categories and subcategories); 76 

FR 24998–99. We concluded in the 

preamble to the proposed rule that we 

could not delist EGUs because our 

appropriate and necessary analysis 

showed that EGUs did not satisfy the 

CAA section 112(c)(9)(B)(i) delisting 

criteria. Id. We did not address in the 

preamble to the proposed rule whether 

EGUs satisfied the CAA section 

112(c)(9)(B)(ii) criteria because EGUs 

failed the first prong of the delisting 

provisions. Id. We reach the same 

conclusion in the final rule and also 

address the delisting petition submitted 

by this commenter. Because we cannot 

delist EGUs, we must regulate them 

under CAA section 112(d). The 

commenter has provided no legitimate 

argument to rebut this conclusion. See 

also previous responses regarding 

regulation under section 112(n)(1)(A). 

Comment: One commenter alleges 

that EPA impermissibly relied on CAA 

section 112(c)(9) to interpret ‘‘hazards to 

public health’’, and argues that the 

‘‘residual risk’’ provisions in CAA 

section 112(f)(2) are more appropriate 

for the establishment of standards for 

EGUs. The commenter stated that by 

using CAA section 112(c)(9)(B)(i) in 

defining ‘‘hazards to public health’’, the 

Agency has seized on the one 

interpretation of the phrase that is 

surely contrary to congressional intent 

and, thus, falls outside the permissible 

range of its interpretative discretion. 

The commenter maintains that the 

‘‘delisting’’ criteria of CAA section 

112(c)(9) are simply irrelevant to the 

decision whether EGU HAP emissions 

will present any ‘‘hazards to public 

health’’ sufficient to warrant regulation 

of those emissions under CAA section 

112. 

The commenter also argues that 

Congress intended that EGUs be treated 

differently from all other ‘‘major 

sources’’ to which the ‘‘delisting’’ 

provisions of CAA section 112(c)(9), and 

the standard-setting provisions of CAA 

section 112(d) necessarily and 

automatically apply. Therefore, 

according to the commenter, the EPA’s 

proposal to utilize the criteria of CAA 

section 112(c)(9) to inform its findings 

under CAA section 112(n)(1)(A) treats 

EGUs exactly the same as all other major 

source categories, is contrary to 

congressional intent, and thus unlawful. 

The commenter goes on to state that in 

exercising its discretion to define 

‘‘hazards to public health’’ as the phrase 

is used in CAA section 112(n)(1)(A), the 

EPA would be better served to consider 

the ‘‘residual health risk’’ provisions of 

CAA section 112(f)(2). Those provisions 

provide a better analogy to the 

establishment of standards for EGUs 

under CAA section 112 than do the ‘‘delisting’’ criteria of CAA section 

112(c)(9). 

The commenter believes the categoryspecific criteria of paragraph (c)(9) are a 

poor fit for an evaluation of ‘‘hazards to 

public health’’ that should reasonably 

include such factors as the affected 

population, the characteristics of 

exposure, the nature of the health 

effects, and the uncertainties associated 

with the data. The commenter states 

that, while CAA section 112(n)(1)(A) 

does not expressly include any 

requirement that EGU emissions be 

regulated with an ‘‘ample margin of 

safety,’’ that standard is more 

appropriate than the ‘‘one-in-a-million’’ 

cancer risk standard of CAA section 

112(c)(9)(B)(i) that EPA proposes to 

employ. 

Response: The commenter 

acknowledges that EPA has broad 

discretion to interpret the phrase 

‘‘hazard to public health’’ but argues 

that the one thing we cannot do is use 

the CAA section 112(c)(9)(B) delisting 

provisions as a benchmark in making 

that interpretation. The commenter 

asserts that the use of the delisting 

standard is clearly contrary to 

Congressional intent but it does not 

provide any substantive rebuttal to our 

conclusion that the CAA section 

112(c)(9) standards reflects the level of 

hazard which Congress concluded 

warranted continued regulation. 

Instead, the commenter reverted to its 

argument that the statute treated EGUs 

differently. The EPA views the disparate 

treatment of EGUs in a different light 

than commenter. While it is true that 

Congress established a different 


srobinson on DSK4SPTVN1PROD with RULES2
9334 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

64 76 FR 24992. 65U.S. EPA 1998. Study of Hazardous Air 

Pollutant Emissions from Electric Utility Steam 

Generating Units—Final Report to Congress. EPA– 

453/R–98–004a. February. 

66U.S. EPA, 1997. 

67 ‘‘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). 

statutory provision governing whether 

to add EGUs as a regulated source 

category under section 112, we do not 

interpret CAA section 112(n)(1)(A) as 

providing Congressional license to 

ignore risks that Congress determined 

warranted regulation for all other source 

categories. Because CAA section 

112(c)(9) defines that level of risk, it is 

reasonable to consider it when 

evaluating whether EGU HAP emissions 

pose hazards to public health. 

The commenter also suggests that the 

‘‘ample margin of safety standard’’ of 

CAA section 112(f)(2) is a better fit than 

the one-in-a-million standard set forth 

in CAA section 112(c)(9)(B)(1) for 

evaluating hazards to public health. The 

commenter asserts that an evaluation of 

‘‘hazards to public health’’ should 

include such factors as the affected 

population, the characteristics of 

exposure, the nature of the health 

effects, and the uncertainties associated 

with the data. However, the EPA did not 

rely solely on the delisting provisions 

for evaluating hazards to public health 

as commenter suggests. In fact, the EPA 

considered all of the factors the 

commenter suggests in making our 

finding.64 Thus, we decline to adjust our 

approach to evaluating hazards to 

public health and the environment 

based on the comments. 

h. 2000 Finding (and 2005 Delisting) 

Comment: Several commenters 

generally support EPA’s 2000 finding 

that regulating HAP emissions from 

EGUs under CAA section 112 is 

‘‘appropriate and necessary.’’ According 

to the commenters, the 2000 finding was 

proper under the CAA and within EPA’s 

discretion, well-supported based on 

sound science available to the Agency at 

the time on the harm from HAP emitted 

by EGUs, and no additional information 

makes the finding invalid. Several 

commenters cited the conclusions of the 

Utility Study 65 and Mercury Study,66

which they assert supported the finding 

and satisfied the only prerequisite for 

the finding. One commenter specifically 

asserted that the 2000 finding was wellsupported 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 Administrator discretion in her 

finding, and that discretionary decision 

should not be overly scrutinized, citing 

court opinion.67 In support of the 

finding, one commenter stated that it 

would not make sense for Congress to 

limit HAP emissions from small 

businesses such as dry cleaners but to 

exempt U.S. EGUs, which are the largest 

sources of many HAP emissions. One 

commenter agreed that finding was 

further supported because numerous 

control options were available to reduce 

HAP emissions. One commenter agreed 

with the 2000 finding that the Agency 

lacked sufficient evidence to conclude 

that non-Hg HAP from EGUs posed no 

hazard. 

The commenters who generally 

supported the 2000 finding also 

commented on specific aspects of the 

finding. Several commenters asserted 

that while the evidence on Hg alone 

supports the finding, the potential harm 

from non-Hg HAP further supported the 

2000 finding. Several commenters noted 

that new science continues to support 

the 2000 finding. Several commenters 

also stated that the ‘‘appropriate’’ 

finding was further supported because 

numerous control options were 

available at the time of the finding that 

would reduce HAP emissions. One 

commenter concurred with EPA that 

regulating natural gas-fired EGUs was 

not appropriate and necessary because 

the impacts due to HAP emissions from 

such units are negligible based on the 

results of the Utility Study. 

Several commenters addressed the 

2005 reversal of the 2000 finding. 

Several commenters specifically 

supported the vacatur of the 2005 

action. Other commenters asserted that 

the 2005 action was proper, and that 

EPA reverted back to the 2000 finding 

in the proposed rule without adequate 

explanation or support. Several 

commenters cited the 2005 action as 

invalidating the 2000 finding, 

specifically noting that EPA concluded 

that ‘‘no hazards to public health’’ 

remained after accounting for emission 

reductions under CAIR. These 

commenters assert that EPA’s current 

position is illegal because EPA took the 

exact opposite position on the 

interpretation of the term ‘‘necessary’’ in 

its 2005 reversal, and, thus, deserves no 

judicial deference. One commenter 

stated that in 2005 EPA recognized the 

potential for excessive regulation 

created by CAA section 112 and 

determined that the 2000 finding lacked 

foundation. 

Several commenters generally 

disagreed with the 2000 finding, with 

two commenters stating that EPA did 

not have a rational justification for it 

and another claiming that it was fraught 

with misinformation and overestimating 

assumptions. One commenter claimed 

that EPA did not explain the terms 

‘‘appropriate’’ and ‘‘necessary’’ in the 

2000 finding and that the emission 

control analysis was inadequate. Two 

commenters stated that the 2000 finding 

was based on data that was more than 

10 years old, which causes serious 

concern regarding the validity of the 

findings because technology, the 

regulatory environment, and the 

economic climate have evolved. 

Furthermore, because the Utility Report 

underestimated emissions controls that 

EGUs would install by 2010 and 

additional controls that would be later 

required by the CSAPR, the basis for 

EPA’s 2000 finding has changed. 

Several commenters stated that a 

‘‘plausible link’’ between anthropogenic 

Hg and MeHg in fish is not an adequate 

reason for the 2000 finding. Several 

commenters claim that EPA only 

identified health concerns for Hg (and 

potentially Ni) but not other HAP from 

coal-fired EGUs in the 2000 finding, 

and, thus, cannot regulate HAP other 

than Hg because the 2000 finding 

authorizes only the regulation of Hg. 

One commenter questioned the Hg 

emissions underlying the 2000 finding, 

specifically the fraction of total 

deposition attributable to U.S. EGUS 

and the fact that EPA projected an 

increase in U.S. EGU emissions from 

1990 to 2010 though emissions actually 

declined. 

Several commenters raised procedural 

issues related to the 2000 finding. 

Several commenters stated that the 2000 

finding failed to provide public notice 

and comment. According to the 

commenters, the CAA requires that any 

decision made under CAA section 

112(n) must go through public notice 

and comment. The commenters further 

stated that the failure to provide public 

notice and comment means that this 

MACT is outside EPA’s statutory 

authority. One commenter stated that 

because the 2000 finding was never 

‘‘fully ventilated’’ in front of the D.C. 

Circuit, the EPA’s authority to regulate 

EGUs under CAA section 112(d) is 

directly at issue. The commenters claim 

that specific issues did not undergo 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9335 

68See UARG v. EPA, 2001 WL 936363, No. 01– 

1074 (D.C. Cir. July 26, 2001). 

69U.S. EPA, 1997. 

70NAS, 2000. 

71 65 FR 79830. 

72 Id. 

73 65 FR 24994–24996. 

74See Chapter 13 of the Utility Study (U.S. EPA, 

1998). 75 76 FR 79827. 

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-thefact 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.68 One 

commenter stated that the 2000 finding 

ignored EO 12866. 

Response: EPA agrees with the 

commenters that the 2000 finding was 

reasonable and disagrees with the 

commenters asserting that the 2000 

finding was unreasonable or failed to 

follow proper procedural requirements. 

The EPA agrees that reviewing courts 

defer to the reasoned scientific and 

technical decisions of an Agency 

charged with implementing complex 

statutory provisions such as those at 

issue in this case. As EPA stated in the 

preamble to the proposed rule, the EPA 

maintains that the 2000 finding was 

reasonable and based on well-supported 

evidence available at the time, including 

the Utility Study, the Mercury Study,69

and the NAS study,70 which all showed 

the hazards to public health and the 

environment from HAP emitted from 

EGUs. New technical analyses 

conducted by EPA confirm that it 

remains appropriate and necessary to 

regulate HAP emissions from EGUs. 

Furthermore, the EPA agrees with the 

commenters on several points raised, 

specifically that EGUs were and remain 

the largest anthropogenic source of 

several HAP in the U.S., that risk 

assessments supporting the 2000 finding 

indicated potential concern for several 

non-Hg HAP, and that several available 

control options would effectively reduce 

HAP emissions from U.S. EGUs. 

The EPA agrees with the commenters 

that Congress did not exempt EGUs 

from section 112(d) HAP emission 

limits while simultaneously limiting 

emissions at other sources with less 

HAP emissions. Congress simply 

provided EPA with a separate path for 

listing EGUs by requiring that the 

Agency evaluate HAP emissions from 

EGUs and determine whether regulation 

under CAA section 112 was appropriate 

and necessary. Since 1990, the EPA has 

promulgated regulations requiring the 

use of available control technology and 

other practices to reduce HAP emissions 

for more than 170 source categories. 

U.S. EGUs are the most significant 

source of HAP in the country that 

remains unaddressed by Congress’s air 

toxics program. The EPA listed EGUs in 

2000 because the considerable amount 

of available data supported the 

conclusion that regulation of EGUs 

under CAA section 112 was appropriate 

and necessary. That finding was valid at 

the time, and EPA reasonably added 

EGUs to the CAA section 112(c) list of 

sources that must be regulated under 

CAA section 112. 

The EPA acknowledges that we did 

not expressly define the terms 

appropriate and necessary in the 2000 

finding, but the finding is instructive in 

that it shows that EPA considered 

whether HAP emissions from EGUs 

posed a hazard to public health and the 

environment and whether there were 

control strategies available to reduce 

HAP emissions from EGUs when 

determining whether it was appropriate 

to regulated EGUs.71 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.72 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,73 and EPA stands 

by the conclusions in that notice. 

Furthermore, the EPA provided an 

interpretation of the terms appropriate 

and necessary that is wholly consistent 

with the 2000 finding. The EPA does 

not agree with the commenters that a 

quantification of emissions reductions 

or a specific identification of the 

available controls was necessary to 

support the 2000 finding and listing. 

The EPA considered the Utility Study 

when making the finding, and that 

study clearly articulated the various 

alternative control strategies that EGUs 

could employ to control HAP 

emissions.74 As to emission reductions, 

the EPA cannot estimate the level of 

HAP emission reductions until the 

Agency proposes a CAA section 112(d) 

standard after a source category is listed. 

The EPA disagrees with commenters 

that suggest it was not ‘‘rational’’ to 

determine that it was appropriate to 

regulate HAP emissions from EGUs due 

to the cancer risks identified in the 

Utility Study or the potential concerns 

associated with other HAP emissions 

from EGUs. Nothing in CAA section 

112(n)(1)(A) suggests that EPA must 

determine that every HAP emitted by 

EGUs poses a hazard to public health or 

the environment before EPA can find it 

appropriate to regulate EGUs under 

CAA section 112. In fact, the EPA 

maintains that it must find it 

appropriate and necessary to regulate 

EGUs under CAA section 112 if it 

determines that any one HAP emitted 

from EGUs poses a hazard to public 

health or the environment that will not 

be addressed through imposition of the 

requirements of the Act. The EPA 

disputes the commenters’ conclusion 

that the 2000 finding was limited to Hg 

and Ni emissions, but, even if it were, 

the EPA reasonably concluded that 

EGUs should be listed pursuant to CAA 

section 112(c) based on the Hg and Ni 

finding. As stated in the 2000 finding, 

cancer risks from some non-Hg metal 

HAP (including As, Cr, Ni, and Cd) were 

not low enough to be to eliminate as 

potential concern.75 Source categories 

listed for regulation under CAA section 

112(c) must be regulated under CAA 

section 112(d), and the D.C. Circuit has 

stated that EPA has a ‘‘clear statutory 

obligation to set emission standards for 

each listed HAP’’. See Sierra Club v. 

EPA, 479 F.3d 875, 883 (D.C. Cir. 2007), 

quoting National Lime Association v. 

EPA, 233 F.3d 625, 634 (D.C. Cir. 2000). 

Therefore, even if EPA concluded that 

CAA section 112(n)(1) authorized a 

different approach for regulating HAP 

emissions from EGUs, the chosen course 

which is supported by the CAA (i.e., 

listing under CAA section 112(c)) 

requires the Agency to regulate under 

CAA section 112(d) consistent with the 

statute and case law interpreting that 

provision. 

The EPA disagrees that there is any 

concern regarding the validity of the 

2000 finding or that the emissions 

information provided in the 2000 

finding makes the finding 

‘‘questionable’’ as stated by some of the 

commenters. The EPA maintains that 

the 2000 finding was sound and fully 

supported by the record available at the 

time, including the future year 

emissions projections. Therefore, the 

listing of EGUs is valid based on that 

finding alone. Even though Hg 

emissions have decreased since the 

2000 finding instead of increasing as 

projected, the new technical analyses 

confirm that Hg emissions from EGUs 

continue to pose hazards to public 


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76 65 FR 79831. 

health and the environment. The EPA 

also indicated potential concern for 

several non-Hg HAP in the 2000 finding. 

It is well established that even small 

amounts of HAP can cause significant 

harm to human health and the 

environment. 

The EPA agrees with the commenters 

who assert that the 2005 action was in 

error and disagrees with the 

commenters that the 2005 action 

invalidated the 2000 finding. As fully 

described in the preamble to the 

proposal, the EPA erred in the 2005 

action by concluding that the 2000 

finding lacked foundation. The 2005 

action improperly conflated the 

‘‘appropriate’’ and ‘‘necessary’’ analyses 

by addressing the ‘‘after imposition of 

the requirements of the Act’’ in the 

appropriate finding as well as the 

necessary finding. The EPA also 

indicated that it was not reasonable to 

interpret the necessary prong of the 

finding as a requirement to scour the 

CAA for alternative authorities to 

regulate HAP emissions from stationary 

sources, including EGUs, when 

Congress provided section 112 for that 

purpose. The EPA asserts that the 2000 

finding was sound and fully supported 

by the record available at the time for all 

the reasons stated in this final rule and 

the proposed rule. The 2005 action 

interpreted the statute in a manner 

inconsistent with the 2000 finding and 

attempted to delist EGUs without 

complying with the mandates of CAA 

section 112(c)(9)(B). See New Jersey, 517 

F.3d at 583 (vacating the 2005 

‘‘delisting’’ action). In the preamble to 

the proposed rule, the EPA set forth a 

revised interpretation of CAA section 

112(n)(1) that is consistent with the 

statute and the 2000 finding. The EPA 

also explained in the preamble to the 

proposed rule why the 2005 action was 

not technically or scientifically sound. 

The EPA specifically addressed the 

errors associated with the 2005 action in 

the preamble to the proposed rule, and 

commenters’ assertions do not cause us 

to revisit these issues. The commenter is 

also incorrect in suggesting that a 

change in interpretation is per se invalid 

and provided no support for that 

position. See National Cable & 

Telecommunications Ass’n, et al., 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 so, the EPA has since conducted new 

technical analyses utilizing the best 

information available in 2010 as several 

years have passed since the 2000 

finding. These new analyses confirm 

that HAP emissions from EGUs continue 

to pose a hazard to public health and 

the environment, even after taking into 

account emission reductions that have 

occurred since 2000 from promulgated 

rules, settlements, and consent decrees. 

See 76 FR 24991. 

Contrary to the commenter’s 

assertion, the EPA did not violate CAA 

section 307(d) by not providing a notice 

and comment opportunity before 

making the December 2000 appropriate 

and necessary finding. One commenter 

challenged EPA’s 2000 finding and 

listing on the same grounds, and the 

D.C. Circuit dismissed the case because 

CAA section 112(e)(4) clearly states that 

listing decisions cannot be challenged 

until the Agency issues final emission 

standards for the listed source category. 

See UARG v. EPA, 2001 WL 936363, No. 

01–1074 (D.C. Cir. July 26, 2001). The 

EPA has provided the public an 

opportunity to comment on both the 

2000 finding and the 2011 analyses that 

support the appropriate and necessary 

determination as part of the proposed 

rule, and anyone may challenge the 

listing in the D.C. Circuit in conjunction 

with a challenge to this final rule. The 

commenters could have also 

commented on the CAA section 

112(n)(1) (e.g., the Utility Study and the 

Mercury Study) studies in 2000 as they 

were included in the docket, but EPA is 

not aware of any comments on those 

studies. In any case, these studies were 

peer reviewed and considered the best 

information available at that time. The 

EPA has fully complied with the 

rulemaking requirements of CAA 

section 307(d). 

The EPA also disagrees with the 

commenters’ characterization of the 

New Jersey case. The D.C. Circuit did 

not say, as one commenter suggested, 

that EPA is not able to consider 

additional information that is collected 

after the 2000 finding; instead, the Court 

stated that EPA could not revise its 

appropriate and necessary finding and 

remove EGUs from the CAA section 

112(c) list without complying with the 

delisting provisions of CAA section 

112(c)(9). See New Jersey, 517 F.3d at 

582–83. The EPA also disagrees with the 

commenter’s assertion that EPA 

disregarded EO 12866 when making the 

2000 finding. As stated in the Federal 

Register notice, the 2000 finding did not 

impose regulatory requirements or costs 

and was reviewed by the Office of 

Management and Budget (OMB) in 

accordance with the EO.76

2. New Technical Analyses 

a. General Comments on New Technical 

Analyses 

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 reemission 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 EGU-attributable 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 

confirm serious health risks from HAP 

exposure. One commenter stated that 

new studies show higher risks to fetuses 

than previously estimated, increasing 

the potential for neurodevelopmental 

effects in newborns. One commenter 

noted that EGUs are a major source of 

HAP, including HCl, HF, As, antimony, 

Cr, Ni, and selenium, all of which 

adversely affect human health. The 

commenter stated that because of these 

health effects, the EPA has ample 

evidence to support a determination 


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77 76 FR 24988. 

78U.S. EPA–SAB, 2011. 

79U.S. EPA–SAB, 2010. 

that non-Hg HAP emissions present a 

risk to human health. 

Other commenters disagreed that the 

new analyses confirm that it remains 

appropriate and necessary to regulate 

U.S. EGUs. One commenter claims that 

EPA tried to use the new technical 

analyses to provide retroactive 

justification for the 2000 finding, which 

only found ‘‘plausible links’’ of health 

effects and ‘‘potential concerns’’ of 

health effects of certain metal emissions, 

dioxins and acid based aerosols. The 

commenter also asserted that none of 

these new analyses demonstrate that 

EGU regulation under section 112 is 

necessary and appropriate. 

One commenter agreed that EPA may 

supplement its finding with new 

information, analyses and arguments to 

reaffirm the 2000 finding up until EPA 

issues final emissions standards. The 

commenter noted that the CAA does not 

freeze the finding. However, another 

commenter argued that EPA does not 

have the authority to rely on new 

technical analyses because the CAA 

requires EPA to make the finding on the 

basis of the Utility Study alone. 

According to that commenter, the EPA 

unreasonably stretched the language of 

CAA section 112 by considering new 

technical analyses. 

Citing a report from Dr. Willie Soon 

that was submitted to the SAB, one 

commenter stated that the new technical 

analyses supporting the proposed rule 

do not conform to the Information 

Quality Act, which requires that 

information relied on by EPA be 

accurate, reliable, unbiased, and 

presented in a complete and unbiased 

manner. 

Response: The EPA agrees with the 

commenters that state that the new 

technical analyses (e.g., the risk 

assessments and technology assessment) 

confirm the 2000 finding and disagrees 

with the commenters that state 

otherwise. The EPA also agrees with the 

commenters that the 2000 finding was 

valid at the time it was made based on 

the CAA section 112(n)(1) studies and 

other information available to the 

Agency at that time. Furthermore, the 

EPA agrees with commenters that the 

final rule will lead to substantial 

reductions in HAP emissions from 

EGUs, that control of the HAP is 

estimated to lead to public health and 

environmental benefits as discussed in 

the RIA, that Hg emissions from U.S. 

EGUs pose a hazard to public health, 

and that non-Hg HAP emissions from 

EGUs pose a hazard to public health. 

Although these new analyses were not 

required, the EPA agrees with the 

commenters that stated that EPA is 

authorized to conduct additional 

analyses to confirm the 2000 finding. 

The EPA disagrees with the 

commenter’s assertion that the Agency 

is not authorized to consider new 

information and at the same time unable 

to use the information available in 2000 

because, according to the commenter, 

that information is ‘‘stale.’’ Under this 

theory, the Agency could not ever make 

an appropriate and necessary finding 

prospectively, thereby excusing the 

Agency from its obligations to protect 

public health and the environment 

because it did not diligently act in 

undertaking its statutory responsibility 

to establish CAA section 112(d) 

standards within two years of listing 

EGUs. See CAA section 112(c)(5). This 

is an illogical result that finds no basis 

in the statute. The EPA also disagrees 

with the commenter’s assertion that 

EPA may not consider new analyses 

conducted after the Utility Study in 

determining whether it is appropriate 

and necessary to regulate EGUs under 

section 112 for the reasons set forth in 

the preamble to the proposed rule.77

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, the EPA maintains that had it 

complied with the statutory mandate to 

issue CAA section 112(d) standards 

within two years of listing EGUs, the 

EPA would likely have declined to 

conduct new analyses. The EPA 

conducted new analyses because over 

10 years had passed since the 2000 

finding, and EPA wanted to evaluate 

HAP emissions from U.S. EGUs based 

on the most accurate information 

available, though the Agency was not 

required to reevaluate the 2000 finding. 

In conducting the new analyses, the 

EPA used this updated information to 

further support the finding. 

The EPA strongly disagrees with the 

commenter that stated that EPA failed to 

conform to the Information Quality Act. 

The EPA used peer reviewed 

information and quality-assured data in 

all aspects of the technical analyses 

used to support the appropriate and 

necessary finding supporting this 

regulation. In addition, the EPA 

submitted the Hg Risk TSD to the SAB 

for peer review, which ‘‘supports the 

overall design of and approach to the 

risk assessment and finds that it should 

provide an objective, reasonable, and 

credible determination of the potential 

for a public health hazard from mercury 

emitted from U.S. EGUs.’’ 78 The SAB 

received the comments from Dr. Willie 

Soon, and had those comments 

available for consideration in their 

deliberations regarding the Hg risk 

analysis. The SAB specifically 

supported elements of the analysis 

criticized by Dr. Willie Soon regarding 

the use of the EPA RfD as a benchmark 

for risk and the connection between Hg 

emissions from U.S. EGUs and MeHg 

concentrations in fish. In addition, the 

risk assessment methodology for the 

non-Hg case studies is consistent with 

the methodology that EPA uses for 

assessments performed for Risk and 

Technology Review rulemakings, which 

underwent peer review by the SAB in 

2009. 79 During the public comment 

period, the EPA also completed a letter 

peer review of the methods used to 

develop inhalation cancer risk estimates 

for Cr and Ni compounds, and those 

reviews were generally supportive. See 

above description of this peer review. 

For the final rulemaking, the EPA 

revised both risk assessments consistent 

with recommendations from the peer 

reviewers. The EPA relies on the SAB’s 

review of the quality of the information 

supporting the analytical results. 

Accordingly, contrary to the 

commenters’ assertions, the EPA acted 

consistently with the Information 

Quality Act as well as EPA’s and OMB’s 

peer review requirements. 

b. Hg Emissions Estimates 

1. Hg Emissions From EGUs 

Comment: The commenters addressed 

the 2005 and 2016 emissions estimates 

for Hg and expressed concern that 

inaccuracies in these emissions 

estimates result in overestimates of risks 

from Hg deposition. Further, 

commenters compared EPA’s 2010 

estimate and 2016 estimate, and stated 

that it is not possible for 29 tons to be 

a correct inventory total for Hg 

emissions in both years given expected 

reductions from CSAPR. In addition, 

commenters specifically commented on 

assumptions included in the Integrated 

Planning Modeling (IPM), including a 

concern that Hg speciation factors used 

by IPM overestimate emissions in 2016. 

Other commenters noted that EGU 

sources are the predominant source of 

U.S. anthropogenic Hg emissions, 

particularly the oxidized and particulate 

forms of Hg that are of primary concern 

for Hg deposition. 

Response: The EPA disagrees with 

commenters’ assertions that the EPA’s 


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80 Jaffe D., Prestbo E., Swartzendruber P., WeissPenzias P., Kato S., Takami A., Hatakeyama S., Kajii 

Y., 2005. ‘‘Export of Atmospheric Mercury From 

Asia,’’ Atmospheric Environment, 39, 3029–3038. 

81 Jaffe D., Strode S., 2008. ‘‘Fate and Transport 

of Atmospheric Mercury From Asia,’’ 

Environmental Chemistry, 5, 121. 

82Pacyna 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. 

83Pirrone 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. 

84Streets, D.G., Zhang, Q., Wu, Y., 2009. 

‘‘Projections of Global Mercury Emissions in 2050.’’ 

Environmental Science & Technology 43, 2983– 

2988. 

85Weiss-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. 

86Pongprueksa, P., Lin, C.J., Lindberg, SE., 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. 

87Selin, NE., Jacob, D.J., Park, R.J., Yantosca, 

R.M., Strode, S., Jaegle, L., Jaffe, D. 2007. ‘‘Chemical 

Cycling and Deposition of Atmospheric Mercury: 

Global Constraints From Observations.’’ Journal of 

Geophysical Research-Atmospheres 112. 

88Streets et al., 2009. 

89Slemr, F., Brunke, E.G., Ebinghaus, R., Kuss, J., 

2011. ‘‘Worldwide Trend of Atmospheric Mercury 

Since 1995.’’ Atmospheric Chemistry and Physics 

11, 4779–4787. 

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 overestimate does 

not affect the 2016 emissions levels. The 

2016 emissions are computed by IPM 

based on forecasts of demand, fuel type, 

Hg content of the fuel, and the 

emissions reductions resulting from 

each unit’s configurations. See IPM 

Documentation for further information, 

which is available in the docket. No 

commenter has provided any evidence 

that the IPM 2016 emissions projection 

methodology resulted in an 

overestimate. 

The EPA acknowledges that the 

current Hg emissions estimate would 

not be the same as the 2016 Hg 

emissions estimate given that 

compliance with CSAPR is anticipated 

to have some Hg co-benefits. For this 

reason, the EPA reflected emission 

reductions anticipated from CSAPR in 

the Hg deposition modeling for 2016 in 

the Hg Risk TSD. In the final rule, the 

EPA revised the estimate of Hg 

emissions remaining from U.S. EGUs in 

2016, which includes additional 

emission reductions anticipated from 

the final CSAPR. The revised estimate 

shows that U.S. EGUs would emit 27 

tons of Hg in 2016. Although EPA does 

not use the current Hg emissions 

estimates in any of the risk calculations, 

the EPA estimates that current Hg 

emissions are 29 tons. Conclusions 

about the trend between current 

emissions and emissions in 2016 are 

limited by the fact that different 

methods were used to compute the two 

estimates, as fully explained in the 

revised Emissions Overview memo in 

the docket. 

The EPA disagrees with the 

commenter’s assertion that incorrect Hg 

emission factors result in incorrect 2016 

emissions. The 2016 projected Hg 

emissions are not based on emissions 

factors. The 2016 Hg emissions are 

computed by the IPM based on forecasts 

of demand, fuel type, Hg content of the 

fuel, and the emissions reductions 

resulting from each unit’s 

configurations. The speciation factors 

referenced by the commenter provide a 

basis for the speciation of total projected 

Hg emissions into particulate, divalent 

gaseous, and elemental species, and do 

not impact the total amount of Hg 

emissions. 

The EPA agrees with commenters 

who noted that EGU sources are the 

predominant source of U.S. 

anthropogenic Hg emissions, and in 

particular the oxidized and particulate 

forms of Hg that are of primary concern 

for Hg deposition. 

2. Global Hg Emissions 

Comment: Several commenters stated 

that predicted Hg deposition relies 

heavily on the amount of gaseous 

elemental Hg used to define the 

boundary and initial conditions of a 

model, e.g., the Hg that enters the U.S. 

from outside the U.S. boundaries. The 

commenters asserted that this is 

especially important because Hg 

emissions from Asia—the region 

immediately upwind of North America 

that affects U.S. Hg deposition 

significantly and also affects it the most 

compared to other regions—are 

expected to continue to 

increase.80 81 82 83 84 85 According to the 

commenter, this would affect the 

amount of Hg in the boundary and 

initial conditions. The commenters 

claim that EPA’s modeling did not 

account for these emission changes, 

thus leading to an overestimate of U.S. 

EGU-attributable deposition in 2016. 

Several commenters noted that Hg 

emissions from U.S. EGUs are small 

when compared to global Hg emissions 

totals and natural sources within the 

U.S. These commenters used a variety of 

information to support alternative 

conclusions about the necessity to 

control U.S. EGU emissions to reduce 

Hg risk: global Hg emissions 

inventories, global and regional 

photochemical modeling research, and 

observation-based assessments. A 

commenter stated that EPA has not 

acknowledged the dramatic decline in 

Hg emissions from U.S. EGUs since the 

late 1990s (approximately 50 percent) to 

the current level or consider the relative 

magnitude of Hg emissions from U.S. 

EGUs compared to other sources, 

natural (such as fires) and humancaused. 

Response: The EPA disagrees that 

boundary and initial conditions used in 

modeling Hg deposition need 

adjustment for several reasons. First, the 

EPA does not use the first 10 days of the 

modeling simulation in the analysis, 

which is more than sufficient to remove 

the influence of initial conditions on Hg 

deposition estimates.86 Second, it is 

difficult to accurately characterize the 

speciation of Hg that flows into the U.S. 

from other countries due to the lack of 

data near the boundaries of the 

modeling domain. Third, the boundary 

inflow for the CMAQ Hg modeling used 

in the Hg deposition modeling are based 

on a global model GEOS–CHEM 

simulation using a 2000 based global 

inventory.87 A recently published 

comparison of global Hg emissions by 

continent for 2000 and 2006 found that 

total Hg emissions from Asia (and 

Oceania) total 1,306 Mg/yr in 2000 and 

1,317 Mg/yr in 2006.88 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 2000.89 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 


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90Caffrey et al., 2010. 

91 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). 

92 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. 

93White, 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. 

94Finley, 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. 

95Seigneur, 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. 

96Seigneur, 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. 

97 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. 

98Rothenberg, SE., 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. 

99Slemr et al., 2011. 

100Streets et al., 2009. 

101Finley et al., 2009. 

global inventories, the EPA concludes 

that the most appropriate technical 

choice is to keep the Hg boundary 

conditions the same between the 2005 

and 2016 simulations. 

The EPA also disagrees with the 

commenters’ assertion that EPA has not 

acknowledged the decline in Hg 

emissions for the U.S. EGUs since the 

late 1990s. The EPA analyzed historical, 

current, and future projected Hg 

emissions from the power generation 

sector, as cited in the preamble to the 

proposed rule. The EPA also disagrees 

with the commenters’ assertions that 

EPA failed to consider the relative 

magnitude of Hg emissions from U.S. 

EGUs compared to other sources. As 

noted in the Hg Risk TSD, the EPA 

modeled Hg emissions from U.S. and 

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, Hg emissions from U.S. 

EGUs pose a hazard to public health 

based on the total of 29 percent of 

modeled watersheds potentially at-risk. 

Our analyses show that of the 29 

percent of watersheds with population 

at-risk, in 10 percent of those 

watersheds U.S. EGU deposition alone 

leads to potential exposures that exceed 

the MeHg RfD, and in 24 percent of 

those watersheds, total potential 

exposures to MeHg exceed the RfD and 

U.S. EGUs contribute at least 5 percent 

to Hg deposition. 

The commenters suggest that Hg 

emissions from U.S. EGUs represent a 

limited portion of the total Hg emitted 

worldwide, including anthropogenic 

and natural sources. While EPA 

acknowledges that Hg emissions from 

U.S. EGUs are a small fraction of the 

total Hg emitted globally, it views the 

environmental significance of Hg 

emissions from U.S. EGUs and other 

domestic sources as a more germane 

consideration. Mercury is emitted from 

EGUs in three forms. Each form of Hg 

has specific physical and chemical 

properties that determine how far it 

travels in the atmosphere before 

depositing to the landscape. Although 

gaseous oxidized Hg and particle-bound 

Hg are generally local/regional Hg 

deposition concerns, all forms of Hg 

may deposit to local or regional 

watersheds. U.S. coal-fired power plants 

account for over half of the U.S. 

controllable emissions of the quickly 

depositing forms of Hg. Although 

emissions from international Hg sources 

contribute to Hg deposition in the U.S., 

the peer reviewed scientific literature 

shows that Hg emissions from U.S. 

EGUs in the U.S. significantly enhance 

Hg deposition and the response of 

ecosystems in the U.S. 90 91 92 93

c. Hg Deposition Modeling 

1. General Comments on Deposition 

Modeling 

Comment: Several commenters stated 

that according to the ENVIRON report, 

the EPA overestimated U.S. EGUattributable Hg deposition by 10 percent 

on average (and up to 41 percent in 

some areas). The commenters claim this 

overestimation is the result of boundary 

condition treatment, the exclusion of 

U.S. fire emissions,94 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,95 96 and EPA should 

present results as estimates of lower and 

upper bound limits. 

Response: The EPA disagrees with the 

information presented by ENVIRON. 

The ENVIRON report is based on the 

misapplication of multiple 

incommensurate modeling studies and 

false premises which include the 

incorrect notion that the boundary 

conditions are over-estimated and the 

idea that EPA should use in-plume 

chemistry that has not been explicitly 

characterized and peer reviewed. 

Reactions that may reduce gas phase 

oxidized Hg in plumes have not been 

explicitly identified in literature. Recent 

studies in central Wisconsin and central 

California suggest the opposite may 

happen; elemental Hg may be oxidized 

to Hg(II) in plumes.97 98 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 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 2000.99 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 

2006 100 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 


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9340 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

100Streets et al., 2009. 

101Finley et al., 2009. 

102 Id. 

103Wiedinmyer, C., Friedli, H., 2007. ‘‘Mercury 

emission estimates from fires: An initial inventory 

for the United States.’’ Environmental Science & 

Technology 41, 8092–8098. 

104Seigneur et al., 2003. 

105Seigneur et al., 2004. 

108 Kolker et al., 2010. 

109Rothenberg et al., 2010. 

110 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. 

this assessment. Finley et al., (2009) 101

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 ratios at this location) may 

not be valid on a broader scale.102

Mercury emissions from wildfires are a 

re-volatilization of previously deposited 

Hg.103 Given that electrical generating 

power plants are currently and 

historically have been among the largest 

Hg-emitting sources, the inclusion of 

wildfire emissions in a modeling 

assessment would necessarily increase 

the contribution from this emissions 

sector. 

The EPA disagrees with the assertion 

that EPA failed to consider the relative 

magnitude of Hg emissions from U.S. 

EGUs compared to other sources and 

disagrees with the interpretation of EGU 

deposition presented in the ENVIRON 

report. As noted in the Hg Risk TSD, the 

EPA modeled Hg emissions from U.S. 

and 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. Hg 

emissions from U.S. EGUs pose a hazard 

to public health based on the total of 29 

percent of modeled watersheds 

potentially at-risk. Our analyses show 

that of the 29 percent of watersheds 

with population at-risk, in 10 percent of 

those watersheds U.S. EGU deposition 

alone leads to potential exposures that 

exceed the MeHg RfD, and in 24 percent 

of those watersheds, total potential 

exposures to MeHg exceed the RfD and 

U.S. EGUs contribute at least 5 percent 

to Hg deposition. The ENVIRON report 

provides no risk analysis of EGU 

contribution. 

The EPA disagrees that research 104 105

presented by the commenter shows that 

U.S. EGU impacts are over-estimated. 

The commenter’s references do not 

support this statement. The references 

provided by the commenter are based 

on Hg modeling that uses models that 

are no longer applied and that are based 

on out-dated Hg chemistry and 

deposition assumptions. Given the 

advances in Hg modeling since the early 

2000s, the EPA does not believe an 

upper and lower bound estimate is 

necessary. 

2. Chemical Reactions 

Comment: Several commenters stated 

that the CMAQ modeling fails to 

account for the chemical reduction of 

gaseous ionic Hg to elemental Hg that 

may occur in EGU plumes. The 

commenters noted that EPA did not use 

the Electric Power Research Institute’s 

(EPRI) Advanced Plume-in-Grid 

Treatment, which includes a surrogate 

reaction to reduce gaseous ionic Hg to 

elemental Hg 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.106 107 A 

detailed description of various plume 

measurement studies is provided in 

EPRI Comments, Section 3.4: Plant 

Bowen, Georgia, Plant Pleasant, 

Wisconsin, and Plant Crist, Florida. One 

commenter believed the impact of grid 

resolution (12 km sized grid cells) on 

the CMAQ modeling was not 

appropriately addressed by EPA. Their 

concerns due to grid resolution include 

the notion that a source’s emissions will 

be averaged over the entire grid cell. 

According to the commenter, such 

averaging causes an artificially fast 

dilution that smoothes out areas of high 

and low deposition, which may limit 

the ability of the model to simulate 

smaller areas of localized high 

deposition. This commenter believed 

that using the APT would address these 

issues. 

Response: The EPA disagrees with the 

commenters’ claims that oxidized Hg 

chemically reduces to elemental 

mercury within the plume. There is no 

evidence of these chemical reactions in 

the scientific literature. The references 

cited by the commenters are from nonpeer reviewed reports and conference 

proceedings. The EPA does not consider 

information presented at conferences or 

industry reports to be peer reviewed 

literature, and consideration of oral 

presentation material would be 

inappropriate. Further, even these cited 

references do not provide sufficient 

information for incorporating the 

supposed reactions into the modeling 

(e.g., specific chemical reactions, 

reaction rates, etc.); rather, the cited 

references only suggest that oxidized gas 

phase Hg could be reduced and 

postulate a possible pathway. 

Recent studies in central Wisconsin 

and central California suggest the 

opposite may happen; elemental Hg 

may be oxidized to Hg(II) in 

plumes.108 109 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.110

Reactions that may reduce gas phase 

oxidized Hg in plumes have not been 

explicitly identified in literature. The 

application of potentially erroneous inplume chemistry that is a fundamental 

component of APT would be 

inappropriate. In addition, the APT is 

not available in the most recent version 

of CMAQ. It would be inappropriate for 

EPA to apply an out of date 

photochemical model with in-plume 

chemistry that has not been shown to 

exist. 

The EPA agrees with the commenter 

that the CMAQ modeling with 12 km 

grid resolution may provide a lower 

bound estimate on EGU contribution as 

higher impacts using finer grid 

resolution are possible. The 

commenter’s assertion that EGU impacts 

are likely higher further supports the 

final conclusions of the exposure 

modeling assessment. The EPA notes 

that the application of a photochemical 

model at a 12 km grid resolution for the 

entire continental U.S. is more robust in 

terms of grid resolution and scale that 

anything published in literature and 

represents the most advanced modeling 

platform used for a national Hg 

deposition assessment. 

3. Modeled Deposition Compared to 

Measured Deposition 

Comment: Multiple commenters 

expressed dissatisfaction related to 

EPA’s model performance evaluation of 

CMAQ estimated Hg deposition. The 

commenters stated that EPA failed to 

evaluate the CMAQ model against realworld measurements and that EPA fails 

to provide first-hand information on wet 

and dry deposition processes. The 

commenters also stated that EPA needs 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9341 

111Bullock, 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, NE., Sistla, G., Vijayaraghavan, K., 2009. ‘‘An 

analysis of simulated wet deposition of mercury 

from the North American Mercury Model 

Intercomparison Study.’’ Journal of Geophysical 

Research-Atmospheres 114. 

112Lyman, 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. 

113Lohman et al., 2006. 

114Seigneur, 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. 

115 Vijayaraghavan, K., Karamchandani, P., 

Seigneur, C., Balmori, R., Chen, S.–Y., 2008. 

‘‘Plume-in-grid modeling of atmospheric mercury.’’ 

Journal of Geophysical Research-Atmospheres 113. 

116Seigneur, 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. 

117 Vijayaraghavan, K., Karamchandani, P., 

Seigneur, C., Balmori, R., Chen, S.-Y., 2008. 

‘‘Plume-in-grid modeling of atmospheric mercury.’’ 

Journal of Geophysical Research-Atmospheres 113. 

118 Id. 

119 Vijayaraghavan et al., 2007. 

120 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. 

121 Yarwood et al., 2003. 

122Evers, David C. et al., 2007. ‘‘Biological 

Mercury Hotspots in the Northeastern United States 

and Southeastern Canada,’’ Bioscience. Vol. 57 No. 

1. p. 29. 

to assess how predicted values of 

deposition compare to Mercury 

Deposition Network (MDN) data and 

how predicted values of ambient 

speciated Hg concentrations compare to 

measurement networks like AMNet and 

SEARCH. In addition, commenters 

stated that EPA used highly aggregated 

performance metrics comparing model 

estimates to observations that they 

believe result in a degraded and lenient 

operational evaluation of the modeling 

system. A commenter suggested that 

EPA’s model performance provides no 

confidence for the intended purpose of 

estimating deposition near point 

sources. One commenter simply noted 

that EPA’s model over-estimated total 

Hg wet deposition at MDN monitors. 

Finally, several commenters noted that 

EPA presented a negative modeled wet 

deposition total in the Air Quality 

Modeling TSD, which is physically 

impossible. 

Response: EPA agrees with the 

commenters that the negative estimate 

for wet deposition in the Air Quality 

Modeling TSD was an error. This error 

reflected an incorrect calculation in the 

post-processing of model and 

observation pairs that only influenced 

the calculation of model performance 

metrics. The error has been fixed, and 

the model performance metrics in the 

revised Air Quality Modeling TSD have 

been updated. This error did not affect 

Hg deposition. In response to 

comments, the EPA provided additional 

model performance evaluation by 

season to the revised Air Quality 

Modeling TSD. In addition, in response 

to comments, the EPA also included 

model performance evaluation for total 

Hg wet deposition for the 36 km 

modeling domain in the revised Air 

Quality Modeling TSD. 

The EPA disagrees that it did not 

conduct an assessment comparing 

CMAQ total Hg wet deposition 

estimates to MDN data. The Air Quality 

Modeling TSD clearly shows a 

comparison of CMAQ estimated total Hg 

wet deposition with MDN data for the 

entire length of the modeling period. 

The CMAQ wet deposition of Hg has 

been and will continue to be extensively 

evaluated against MDN sites.111 There is 

no dry deposition monitoring network, 

which precludes evaluating CMAQ dry 

deposition processes. The EPA disagrees 

that an evaluation of ambient speciated 

Hg against routine monitor networks 

such as AMNet or SEARCH would be 

useful for this particular modeling 

application. The AMNet Hg network did 

not exist in 2005, which is EPA’s 

baseline model simulation time period, 

and the SEARCH network started 

making preliminary measurements of 

Hg at one or two sites in 2005. In 

addition, measurement artifacts related 

to gaseous oxidized Hg are difficult to 

quantify and make direct comparison to 

model estimates problematic.112

Considering the problems associated 

with TEKRAN measurements of ambient 

Hg and the sparse nature of routine 

measurements in the U.S., the EPA did 

not compare ambient Hg against model 

estimates. 

The EPA disagrees that the model 

performance presented in the air quality 

TSD is insufficient. The EPA asserts that 

the model performance evaluation is 

generally similar to the level of model 

performance presented in literature. 

One commenter presented the results of 

several Hg modeling studies as 

providing information that the 

commenter believes to be relevant for 

this assessment in terms of model 

performance metric estimation and the 

level of model performance evaluation 

shown for assessments modeling Hg 

near point sources. For example, one 

cited study titled ‘‘Modeling Mercury in 

Power Plant Plumes’’ models nearsource Hg chemistry from U.S. EGUs, 

but provides absolutely no information 

about model performance evaluation.113

Another commenter identified two 

studies as supposedly having Hg 

modeling results that are applicable to 

EPA’s analysis.114 115 These studies 

present similar model performance 

metrics as EPA. The EPA disagrees that 

the Agency used ‘‘highly aggregated 

performance metrics’’ that result in 

degraded and lenient model evaluation. 

The studies presented 116 117 as relevant 

for point source mercury modeling use 

an approach to aggregate the operational 

performance metrics across many 

monitor locations as did EPA; however, 

these articles calculate long term annual 

averages of modeled and observed total 

Hg wet deposition before estimating 

performance metrics. It is common 

practice to pair modeled estimates and 

observations in space and time (weekly 

in this case) and estimate performance 

metrics, then average all the metrics 

together. The latter is the approach 

taken by the EPA and should have been 

taken by the studies presented by the 

commenter. The EPA used a more 

stringent approach to match 

observations and predictions and 

aggregation of operational model 

performance. The EPA agrees that the 

commenter accurately restated total wet 

deposition model performance 

information provided by the EPA in the 

Air Quality Modeling TSD. To provide 

context, other Hg modeling studies 

show a positive bias for annual total Hg 

wet deposition.118 119 An annual Hg 

modeling application done by 

ENVIRON 120 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.121 These 

results indicate a very large overestimation tendency. The model 

performance shown by EPA is 

consistent with other long-term Hg 

modeling applications. 

4. Excess Local Deposition From Hg 

Emissions From U.S. EGUs (Deposition 

Hotspots) 

Comment: One commenter stated that 

reducing Hg will benefit local 

environments. The commenter stated 

that a 2007 study confirmed the 

presence of Hg ‘‘hotspots’’ downwind 

from coal-fired power plants and 

confirmed that coal-fired power plants 

within the U.S. are the primary source 

of Hg to the Great Lakes and the 

Chesapeake Bay.122 The commenter also 

stated that the study is consistent with 

a major Hg deposition study conducted 


srobinson on DSK4SPTVN1PROD with RULES2
9342 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

123Cohen, et al., 2004. ‘‘Modeling the 

Atmospheric Transport and Deposition of Mercury 

to the Great Lakes,’’ Environmental Research 95, 

(247–265). 

124 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. 

125Seigneur et al., 2006. 

126U.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. 

127Evers et al., 2007. 128Sullivan 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. 

129 Kolker, et al., 2010. 

130Caffrey, 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. 

131 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. 

by the EPA and the University of 

Michigan that concluded that 

approximately 70 percent of Hg wet 

deposition resulted from local fossil fuel 

emissions in the region.123

One commenter agreed with the 

Agency’s assessment of the potential for 

deposition ‘‘hotspots’’ that shows that 

Hg deposition near EGUs can be three 

times as large as the regional average. 

The commenter stated that this excess 

Hg deposition would substantially 

increase the health and environmental 

risks associated with emissions at these 

sites. The same commenter also stated 

that EPA applied a conservative 

methodology to quantify near-source Hg 

deposition. The commenter stated that 

maximum excess local Hg deposition 

may be significantly underestimated by 

averaging high deposition sites 

downwind of an EGU in the direction of 

prevailing winds with lower excess 

deposition at locations close to but 

frequently upwind of the facility. The 

same commenter suggests that had EPA 

used CMAQ and individual 12x12 km2

grid cells to quantify local deposition, 

the 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.124 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 coalfired power plants. According to the 

commenter, the EPA’s use of a 50 km 

radius to calculate hotspots is flawed. 

The commenter stated that modeling 

studies show that deposition of Hg 

emitted from power plants is not 

confined to a 50-km radius around the 

plants and that most emissions from 

power plants travel beyond 50 km.125

Several commenters stated that the 

EPA does not adequately define 

hotspots in this proposed rule. Those 

same commenters cited a previous EPA 

definition of hotspots as ‘‘a waterbody 

that 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).126 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.127 One of those two commenters 

noted that others have defined 

‘‘hotspots as a spatially large region in 

which environmental concentrations far 

exceed expected values, with such 

values (i.e. concentrations) being 2 to 

three standard deviations above the 

relevant mean.’’ 128

One commenter stated that Hg 

concentrations are not always highest at 

sites closest to a major source. The 

commenter referred to a study 129 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 coalfired EGU than when measured 100 km 

away. The commenter stated that these 

findings contradict the idea, implicit in 

EPA’s hotspot analysis, that reactive 

gaseous Hg decreases with distance 

from a large point source. 

One commenter provided information 

from a non-peer reviewed report with 

wet Hg deposition measurements 

downwind from the coal-fired power 

plant Crist in Pensacola, FL. The 

commenter stated that using the same 

data from these same wet deposition 

sites, one study 130 found that Hg wet 

deposition and concentrations did not 

differ in a statistically significant 

manner among these three sites and that 

the concentrations values were similar 

to those from Mercury Deposition 

Network (MDN) sites that are more than 

50 km away from Plant Crist located 

along the Northern Gulf of Mexico coast. 

Another commenter stated that Plant 

Crist installed a wet scrubber and has 

operated that scrubber continuously 

since December 2009. The commenter 

stated that the scrubber reduces total Hg 

emissions by about 70 percent and 

reduces emissions of reactive gaseous 

Hg by about 85 percent. The commenter 

cited a non-peer reviewed conference 

presentation 131 that reported changes in 

Hg wet deposition relative to historic 

measurements. The commenter stated 

that, taken collectively, these findings 

show that increased local total Hg 

deposition, possibly due to EGUs, and 

deposition changes due to changes in 

EGU emissions, are small. 

Two commenters stated that a study 

by the Department of Energy (DOE) that 

collected and analyzed soil and 

vegetation samples for Hg near three 

U.S. coal-fired power plants—one in 

North Dakota, one in Illinois, and one in 

Texas—found no strong evidence of 

‘‘hotspots’’ around these three plants. 

Two commenters stated that analysis 

of long-term trends in Hg emissions 

from coal-fired EGUs and wet 

deposition in Florida concluded that 

statistical analysis does not show 

evidence of a significant relationship 

between temporal trends in Hg 

emissions from coal-fired EGUs in 

Florida and Hg concentrations in 

precipitation during 1998 to 2010. 

Two commenters stated that the Hg 

Risk TSD presents no information, 

summary statistics, and/or actual 

calculations showing how excess 

deposition within 50 km of an EGU 

source is obtained. The commenters 

stated that by assessing only Hg 

deposition attributable to EGUs, the 

EPA fails to provide a context for all 

other sources of Hg deposition. The 

commenters stated that the Agency does 

not explain why deposition from the top 

10 percent of EGU Hg emitters does not 

decline, despite substantial reductions 

in modeled Hg emissions from those 

sources between 2005 and 2016. 


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132Edgerton et al., 2006. 

133 Driscoll et al., 2007. 134EPRI, 2010. 

According to the commenters this 

implies that the top 10 percent EGUs 

may have approximately as much of a 

regional effect as a local effect. 

Two commenters stated that the 

CMAQ model has limitations when 

used to predict local deposition and 

tends to overestimate local deposition. 

The commenters stated that modeling 

studies using either a plume model or 

an Eulerian model predict that 91 to 96 

percent of the Hg emitted by an EGU 

travels beyond 50 km.132

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 

studies 133 cited by those commenters 

that corroborate EPA’s conclusions. 

However, the EPA disagrees with those 

commenters’ characterization of the 

methodology used to calculate the 

potential for excess local deposition. In 

response, the EPA has clarified the 

methodology in the new TSD entitled 

‘‘Technical Support Document: 

Potential for Excess Local Deposition of 

U.S. EGU Attributable Mercury in Areas 

near U.S. EGUs,’’ which is available in 

the docket. 

The EPA agrees that there is no 

generally agreed-upon definition of 

‘‘hotspot.’’ As discussed in the preamble 

and TSD, for the purposes of the 

appropriate and necessary finding, the 

EPA determined that information on the 

potential for excess deposition of Hg in 

areas surrounding power plants would 

be useful in informing the finding. The 

EPA disagrees with some commenters 

who misinterpreted the intent of the Hg 

deposition hotspot analysis. 

Specifically, the analysis is not of ‘‘Hg 

hotspots’’, which are often defined as 

high Hg concentration in fish, but rather 

of Hg deposition hotspots, defined as 

excess local Hg deposition around U.S. 

EGUs, as clarified in the new Local 

Deposition TSD. Because EPA did not 

identify ‘‘Hg hotspots’’ of high Hg 

concentrations in fish, the EPA’s MeHg 

water quality criterion of 0.3 mg/kg is 

irrelevant to EPA’s analysis of excess 

local Hg deposition for this rule. 

The EPA disagrees that the analysis 

assumes that deposition of Hg is 

confined to a 50-km radius around 

power plants. The purpose of the EPA’s 

analysis was to evaluate whether there 

existed ‘‘excess deposition of Hg in 

nearby locations within 50 km of EGUs 

that might result in Hg deposition 

‘hotspots’.’’ As explained further in the 

new TSD, the EPA calculated the 

average EGU-attributable deposition 

(based on CMAQ modeling of Hg 

deposition) in the area 500 km around 

each plant and the average EGUattributable deposition in the area 50 km 

around each plant. The difference 

between those two values is the excess 

local deposition around the plant. The 

EPA does not suggest Hg emissions from 

power plants stop at 50 km from the 

source. Some portion of EGU emissions 

deposit before 50 km, and some portion 

travels beyond 50 km. In addition, Hg 

disperses as it transports, so the average 

EGU contribution can be lower in areas 

beyond 50km relative to areas within 

50km even though Hg emissions from 

EGUs are depositing into U.S. 

watersheds. 

The EPA disagrees with some 

commenters’ interpretation of the 

analysis as being focused on local 

deposition from all sources. In fact, the 

focus was on excess local deposition, 

rather than all local deposition. The 

EPA has clarified the purpose of the 

excess local deposition analysis in the 

new TSD. The EPA agrees that all EGUs 

add to local deposition, however, not all 

EGUs have local deposition that greatly 

exceeds regional deposition, which is 

the relevant question. The EPA 

disagrees that the DOE study referenced 

by the commenters attempted to assess 

the same analytical question as EPA’s 

analysis. The DOE study focused on 

comparisons of total deposition near 

and far from power plants. The EPA’s 

analysis did not focus on total Hg 

deposition, because as EPA 

acknowledges throughout its analysis, 

global sources of Hg deposition account 

for a large percentage of total Hg 

deposition. In addition, including global 

sources of Hg deposition would obscure 

the comparison of local and regional 

U.S. EGU-attributable Hg deposition. 

Because of regional deposition from 

both domestic and global sources of Hg, 

total Hg deposition at any location is 

unlikely to be highly correlated with 

local sources. The EPA’s analysis 

focused on U.S. 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 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 excess local 

deposition is on average three times the 

regional EGU-attributable deposition 

around those plants. 

The EPA disagrees that the Hg Risk 

TSD did not provide sufficient 

information regarding the excess local 

deposition calculation. Nonetheless, the 

EPA has further clarified the 

methodology in the new Local 

Deposition TSD, including further 

descriptions of the method used to 

calculate the local and regional 

deposition around power plants along 

with maps and tables of results. 

The EPA disagrees with the 

commenters that stated that the 

discussion of local deposition in the Hg 

Risk TSD did not demonstrate that Hg 

deposition from the top 10 percent of 

EGU Hg emitters declines. Table 1 of the 

new Local Deposition TSD clearly 

shows that mean local deposition 

(within 50km of a plant) for the top 10 

percent of emitters declines from 4.89 

micrograms per cubic meter (mg/m3) to 

1.18 mg/m3. What does not change is the 

percent local excess for EGUattributable 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 that the 

information 134 provided by the 

commenter regarding the Crist plant and 

other coal-fired power plants in Florida 

is relevant to EPA’s analysis of excess 

local deposition from U.S. EGUs 

because it is based on measurements of 

wet Hg deposition without 

consideration of dry Hg deposition, 

which can be a significant component of 

Hg deposition. 

The EPA disagrees with the 

commenter regarding the interpretation 

of the literature related to the spatial 

extent of deposition of Hg emitted by 

U.S. EGUs. The EPA also disagrees that 

the peer-reviewed CMAQ model has 

limitations for this application or 

overestimates local deposition. The 

commenter does not provide any 

credible support for the assertion that 

grid-based models typically 

overestimate local deposition 

surrounding EGUs. The EPA maintains 

that the CMAQ photochemical model 

represents the best science currently 

available in simulating atmospheric 


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9344 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

135Seigneur et al., 2006. 136 Id. 

137Harris., 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). 

138Orihel 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. 

139Scudder 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. 

140 Grigal D.F., 2002. ‘‘Inputs and Outputs of 

Mercury from Terrestrial Watersheds: A Review,’’ 

Environmental Review, 10, 1–39. 

141 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. 

142 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. 

143Lindberg S. et al. 2007. ‘‘A synthesis of 

progress and uncertainties in attributing the sources 

of mercury in deposition.’’ Ambio 36(1): 19–32. 

144Orihel 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. 

chemistry, transport, and deposition 

processes. 

The study 135 cited by the commenter 

to support the notion that 91 to 96 

percent of Hg emitted from power plants 

travels beyond 50 km is based on a 

photochemical transport model (the 

TEAM model) that does not employ 

current state-of-the-science and is not 

actively developed or updated. 

Furthermore, the modeling is based on 

grid cells that are 20 km in size, which 

limits generalizability to EPA modeling 

performed at 12 km grid resolution 

using a state of the science 

photochemical grid model. The cited 

modeling study ignores dry deposition 

of elemental Hg from all sources, an 

assumption that clearly limits the 

regional impacts from sources.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 (where emissions from U.S. 

EGUs are set to zero) and the baseline 

model simulations are directly 

compared. Finally, the modeling study 

cited by the commenter presents an 

illustration of gridded total annual Hg 

deposition from the TEAM model for 

the eastern U.S. that clearly shows 

elevated annual total Hg deposition in 

the vicinity of coal-fired power plants in 

the Ohio River Valley and northeast 

Texas. 

d. Hg Risk TSD 

1. Assumption of Linear Proportionality 

in Relationship Between Changes in Hg 

Deposition and Changes in Fish Tissue 

Hg Concentrations (Mercury Maps) 

Comment: Several commenters 

criticized EPA’s assumption that 

changes in deposition resulting from 

U.S. EGU emissions of Hg will result in 

proportional changes in fish tissue Hg 

concentrations at the watershed level, as 

supported by the Mercury Maps 

modeling exercise. According to one 

commenter, the Mercury Maps model 

has limited capability to adequately 

determine bioaccumulation in fish. The 

same commenter stated that the 

Mercury Cycling Model (MCM) 

developed by EPRI is a more rigorous 

model that was developed expressly to 

evaluate the relationship between 

changes in atmospheric Hg deposition 

to waterbodies and changes in fish 

tissue MeHg levels. 

Several commenters stated that the 

Mercury Maps model has many 

deficiencies. Those commenters stated 

that Mercury Maps is a static model 

unable to account for the dynamics of 

ecosystems that affect Hg 

bioaccumulation in fish, cannot 

consider non-air Hg inputs to 

watersheds, and assumes reductions in 

airborne Hg lead to proportional 

reductions in fish MeHg concentrations. 

Another commenter claimed that data 

that demonstrate a steady-state 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.137 138

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 

study 139 showed that sheet flow and 

drainage, not deposition, dominated 

input to the waterbodies it surveyed. 

The commenter stated that sheet flow 

and drainage could contain Hg and thus 

complicate the relationship that EPA 

asserts is linear and direct. Another 

commenter cited Figure 2–17 in the Hg 

Risk TSD as showing that there is no 

well-defined relationship between Hg 

deposition and MeHg concentrations in 

fish tissue on a national basis. 

Several commenters provided 

comments related to the assumption 

that fish tissue Hg levels used in the 

analysis represent a steady-state. One 

commenter stated that given the 

demonstrated lag time in response to 

deposition change, it is logical to 

conclude that a lag time needs to be 

incorporated in Mercury Maps to adjust 

the estimation of how much fish tissue 

MeHg levels decrease in response to 

decreases in Hg deposition attributable 

to U.S. EGUs. According to the same 

commenter, the METAALICUS study 

shows that there is a lag time (and a 

non-proportional response) after 3–4 

years. The same commenter noted that 

there are numerous factors that 

influence lag time including (1) 

watershed characteristics,140 (2) the fact 

that watersheds may act as legacy 

sources releasing Hg when disturbed,141

(3) the magnitude of emission 

reductions and subsequent changes in 

atmospheric deposition need to be 

weighed against the amount of Hg 

already in an ecosystem,142 (4) the 

distance of an ecosystem from Hg 

sources,143 and (5) the fact that Hg 

deposited to aquatic ecosystems 

becomes less available for uptake by 

biota over time.144 Another commenter 

stated that additional Mercury Maps 

assumptions do not allow for 

considerations of lag in response to 

changes in: (1) Deposition, (2) legacy 

sources of Hg such as mining, (3) 

historical Hg deposition, (4) natural Hg 

levels in fish, (5) ecosystem dynamics 

over time, or (6) the relative source 

contributions over time. Another 

commenter stated that lag times need to 

be included in the modeling and be able 

to vary from watershed to watershed 

and sometimes even from waterbody to 

waterbody within a watershed. Several 

commenters stated that the emission 

rates of Hg due to U.S. sources have 

been decreasing for more than a decade, 

while emissions due to sources outside 

the U.S. have been increasing. For this 

reason, the commenter asserted that the 

system is not at steady-state, a basic 

premise of the model. Another 

commenter stated that while the time 

lag for deposition to reach a waterbody 

is mentioned in the Hg Risk TSD, there 

is no discussion of the fact that a 


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145U.S. EPA–SAB, 2011. 

146U.S. EPA–SAB, 2011. 

147Orihel et al., 2007. 

148Orihel et al., 2008. 

149Harris et al., 2007. 

150U.S. EPA–SAB, 2011. 

151U.S. EPA–SAB, 2011. 

152Orihel et al., 2007. 

153Orihel et al., 2008. 

154Orihel et al., 2007. 

portion of the deposition is unlikely to 

reach the water at all. 

One commenter believes EPA 

incorrectly implied that its EGU risk 

estimates using Mercury Maps are 

underestimated because they do not 

account for legacy EGU-attributable 

deposition, which EPA assumes to be 

higher. 

One commenter stated that while EPA 

properly screened out watersheds with 

significant current non-air sources of 

Hg, the EPA did not adequately screen 

out watersheds with significant Hg 

contributions from non-air sources, 

specifically watersheds with historic Hg 

or gold mining or other industrial Hg 

discharges. The same commenter stated 

that EPA’s study was not geographically 

balanced and was dominated by rivers 

in the coastal region of the southeast 

that has numerous wetlands, which are 

favorable locations for methylation and 

have conditions that are not typical of 

much of the rest of the U.S. 

Response: The EPA disagrees with the 

commenters who challenged the 

assumption of a linear proportional 

relationship between changes in U.S. 

EGU deposition and fish tissue Hg 

levels. The EPA specifically asked the 

SAB to evaluate EPA’s assumption of 

linear proportionality in the 

relationship between Hg deposition and 

fish tissue MeHg concentrations, 

supported by the Mercury Maps 

analysis. The SAB peer review 

committee provided the following 

overall response, which generally 

supports EPA’s approach: 

The SAB agrees with the Mercury Maps 

approach used in the analysis and has cited 

additional work that supports a linear 

relationship between mercury loading and 

accumulation in aquatic biota. These studies 

suggest that mercury deposited directly to 

aquatic ecosystems can become quickly 

available to biota and accumulated in fish, 

and reductions in atmospheric mercury 

deposition should lead to decreases in 

methylmercury concentrations in biota. The 

SAB notes other modeling tools are available 

to link deposition to fish concentrations, but 

does not consider them to be superior for this 

analysis or recommend their use. The 

integration of Community Multiscale Air 

Quality Modeling System (CMAQ) deposition 

modeling to produce estimates of changes in 

fish tissue concentrations is considered to be 

sound. Although the SAB is generally 

satisfied with the presentation of 

uncertainties and limitations associated with 

the application of the Mercury Maps 

approach in qualitative terms, it recommends 

that the document include quantitative 

estimates of uncertainty available in the 

existing literature.145

The SAB peer review committee 

specifically addressed the MCM 

suggested by the commenter and had 

the following response: 

The SAB agrees with the application of 

Mercury Maps in this assessment. There are 

other modeling tools capable of making a 

national scale assessment, such as the 

Regional Mercury Cycling Model (R–MCM). 

However, the R–MCM is more data intensive 

and the results produced by the two model 

approaches should be equivalent. 

The R–MCM, a steady-state version of the 

time-dependent Dynamic Mercury Cycling 

Model, has been publicly available to and 

used by the EPA (Region 4, Athens, 

Environmental Research Laboratory) for a 

number of years. R–MCM requires more 

detail on water chemistry, methylation 

potential, etc., and yields more information 

as well. Substantial data support the Mercury 

Maps and the R–MCM steady-state results, so 

that the results of the sensitivity analysis and 

the outcomes from using the alternative 

models would be equivalent between the two 

modeling approaches. Though running an 

alternative model framework may provide 

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.146

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.147 148 149 These studies suggested 

that mercury deposited directly to 

aquatic ecosystems can become quickly 

available to biota and accumulated in 

fish, and that reductions in atmospheric 

mercury deposition should lead to 

decreases in methylmercury 

concentrations in biota. These results 

substantiate EPA’s assumption that 

proportionality between air deposition 

changes and fish tissue methylmercury 

level changes is sufficiently robust for 

its application in this risk 

assessment.’’ 150

Based on the responses of the SAB 

peer review committee, the EPA’s use of 

the linear proportionality assumption, 

supported by the Mercury Maps 

analysis, is well-supported. 

The EPA also disagrees with 

commenters’ interpretation of Figure 2– 

17. As stated in the Hg Risk TSD, while 

this figure is 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.’’ 151

In response to recommendations from 

the SAB, the EPA expanded the 

discussion of uncertainties associated 

with the linearity assumption, including 

uncertainties related to the potential for 

sampled fish tissue Hg level to reflect 

previous Hg deposition and the 

potential for non-air sources of Hg to 

contribute to sampled fish tissue Hg 

levels. Each of these sources of 

uncertainty may result in potential bias 

in the estimate of exposure associated 

with current deposition. The EPA took 

steps to minimize the potential for these 

biases by (1) only using fish tissue Hg 

samples from after 1999, and (2) 

screening out watersheds that either 

contained active gold mines or had 

other substantial non-U.S. EGU 

anthropogenic emissions of Hg. The 

SAB commented that EPA’s approach to 

minimizing the potential for these 

biases to affect the results of the risk 

analysis appears to be sound and that 

additional criteria that could be applied 

are unlikely to substantially change the 

results. As a result, the EPA disagrees 

with the commenter that EPA’s 

screening process is inadequate. In 

addition, we conducted several 

sensitivity analyses to gauge the impact 

of excluding watersheds with the 

potential for non-EGU Hg emissions, 

and found that the results were robust 

to these exclusions. 

In response to specific comments 

regarding the use of the Mercury Maps 

model, the EPA clarifies that the Hg 

Risk TSD did not directly use the 

Mercury Maps model. Instead, the EPA 

applied an assumption of linear 

proportionality between changes in Hg 

deposition and changes in MeHg 

concentrations in fish that is supported 

by the Mercury Maps modeling. By 

assuming steady-state conditions in 

apportioning fish tissue Hg levels and 

risk, the EPA does not attempt to project 

lag times. Recent research cited by the 

SAB152 153 154 identifies relatively rapid 

response of fish tissue Hg to changes in 

Hg loading, which suggests that fish 

tissue Hg levels could react more 


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9346 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

155U.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. 

156U.S. EPA–SAB, 2011. 

157This change led to a very small increase in the 

number of watersheds with populations potentially 

at-risk. In the Hg Risk TSD accompanying the 

proposed rule, approximately 4 percent of modeled 

watersheds were excluded based on the SES-based 

filtering criteria. 

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. While fish tissue may respond 

rapidly to changes in Hg loading, this 

does not change the fact that previously 

emitted Hg from U.S. EGUs can be reemitted and re-deposited, and thus 

affect Hg concentration in fish. 

2. Characterization of Subsistence 

Fishing Populations and Exposure 

Scenario 

Comment: Several commenters stated 

that EPA provides no clear definition of 

subsistence, near subsistence, or highend fish consumption, instead assuming 

that poverty is a direct indication of 

subsistence fishing and high-end fish 

consumption. One commenter stated no 

documentation exists to supports these 

assumptions. Another commenter stated 

that EPA’s definitions of subsistence 

fishers in the Hg Risk TSD are not 

consistent with earlier EPA documents 

and are used inconsistently throughout 

the Hg Risk TSD. Several commenters 

stated that while subsistence fishing can 

be associated with poverty, poverty does 

not indicate subsistence fishing. One 

commenter stated that by including 

watersheds with as few as 25 members 

of individuals living in poverty, the EPA 

overstates risks. 

One commenter stated that it is 

unclear what literature the Agency says 

‘‘generally supports the plausibility of 

high-end subsistence-like fishing * * * 

to some extent across the watersheds’’ 

and stated that if other studies exist, the 

EPA should provide the values for 

comparison. 

One commenter stated that EPA 

combined two parameters with differing 

scales to establish the geographic unit 

used in the Hg Risk TSD risk 

assessment. The HUC watersheds are 

based on average about 35 square miles 

in size, while U.S. census tracts used to 

identify watersheds relevant for 

subpopulations of interest—cover a few 

tenths to hundreds of square miles. 

Several commenters stated that it is 

unclear how the analysis handled 

differences in geographic resolution 

between watersheds and census tracts 

were. 

One commenter stated that the 

procedure for assigning census tracts 

could bias exposure outcomes. For 

example, the commenter stated that a 

single influential census tract in a 

watershed could drive risk, even if the 

watershed had only a minimal number 

of fish samples. The commenter stated 

that this possibility is a concern in 

urban areas, which account for the 

majority of census tracts, because these 

census tracts are more likely to be 

included in a risk analysis because they 

have more than 25 people living in 

poverty. The commenter stated that 

these census tracts may drive the 

extremes of the distribution without 

regard to the actual number of highlevel, 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’s assumption would result in 

any densely populated urban census 

tract with a single fish tissue sample 

being assigned to a modeled watershed 

with populations potentially at-risk, 

regardless of the actual degree of 

recreational or subsistence fishing 

taking place there. 

Response: The EPA agrees with the 

comments that subsistence fish 

consumption was not clearly defined, 

and we have provided a clearer 

definition in the revised Hg Risk TSD, 

however, this clarification does not 

result in any changes to the quantitative 

analysis. In the revised Hg Risk TSD, the 

EPA clarifies that ‘‘subsistence fishers’’ 

are defined as individuals who rely on 

noncommercial fish as a major source of 

protein.155 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 

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.156

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 12 km2. 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, the EPA 

modified the female subsistence 

scenario to apply equally to all 

watersheds with fish tissue Hg data 

based on the likelihood that these 

populations have the potential to fish at 

most watersheds. As described in the 

revised Hg Risk TSD, the EPA made this 

change in response to SAB’s concerns 

regarding the potential exclusion of 

watersheds with fewer than 25 

individuals and regarding coverage for 

high-end recreational fish 

consumption.157 Thus, concerns 

regarding the use of census data to 

select watersheds with the potential for 

subsistence fishing no longer apply to 

this scenario. However, for the 

remaining subsistence scenarios, the 

EPA continues to use U.S. Census tractlevel data to evaluate the presence of a 

‘‘source population’’ in the vicinity of 

the watershed being modeled for risk. In 

this context, the EPA uses the U.S. 

Census data to assess whether a 

socioeconomic status (SES)- 

differentiated group similar to the 

particular type of subsistence fisher 

being modeled (e.g., poor Hispanics) are 

located in the vicinity of the watershed. 

If a source population is nearby, then 

this increases the potential that 

subsistence fishing activity could occur 

for that population scenario. 

The EPA continues to model risk for 

white and black subsistence fishers 

active in the southeast and for Hispanics 

assessed nationally. In this case, the 

EPA links poverty with subsistence 

fishing, as EPA only modeled locations 

with poor source populations. However, 

in modeling these three populations, the 


srobinson on DSK4SPTVN1PROD with RULES2
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158Burger, 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. 

159Morgan, 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. 

160Armbruster 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. 

162Farias 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. 

163Perello ́ G., Martı ́-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. 

164Torres-Escribano S., Ruiz A., Barrios L., Ve ́lez 

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. 

165Morgan et al., 1997. 

166 Id. 

167 Id. 

168Farias et al., 2002. 

169Perello ́ et al., 2008. 

170Torres-Escribano et al., 2011. 

171Armbruster et al., 1988. 

172 Gutenmann et al., 1991. 

173Morgan et al., 1997. 

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, and, 

thus, can be included 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, it is likely that EPA excluded 

other watersheds from the analysis 

where this type of subsistence fishing 

activity occurs due to a lack of fish 

tissue Hg data. 

While EPA agrees with the comment 

that it is likely that exposure to total 

MeHg through commercial fish 

consumption represents a more 

significant risk for the general 

population than consumption of 

freshwater fish obtained through selfcaught fishing activity, exposure to total 

MeHg through self-caught fish 

consumption is the most significant risk 

for subsistence fishing populations and 

high-end recreational fishers. For the 

subset of these populations that focus 

their fishing activity in freshwater 

streams and lakes, it is also the case that 

they will experience a higher fraction of 

MeHg exposure attributable to U.S. EGU 

Hg emissions. As a result, the EPA 

focused the risk assessment on 

subsistence fishers active at inland 

freshwater watersheds because they are 

likely to experience the highest levels of 

individual risk as a result of exposure to 

U.S. EGU-attributable Hg. 

3. Cooking Loss Adjustment Factor 

Comment: Several commenters stated 

that EPA did not justify the selection of 

a cooking loss factor of 1.5 that, 

according to one commenter, increases 

estimated intake by 50 percent, thus 

increasing the daily MeHg intake rate by 

a constant factor of 33 percent and also 

increasing any resulting (HQ) risk 

estimate by a similar factor. Several 

commenters stated that the source of 

EPA’s selected loss factor 159 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 highend 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 

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 highend of the range of values in the 

literature. The EPA selected the Morgan 

study 165 as the basis for the food 

preparation/cooking adjustment factor 

because it focused on the types of 

freshwater fish species representative of 

what might be consumed by subsistence 

fishing populations (i.e., walleye and 

lake trout). This study 166 provides a 

range of adjustment factors for each fish 

type including 1.1 to 1.5 for walleye and 

1.5 to 2.0 for lake trout. Given these two 

ranges, the EPA determined it to be 

reasonable to take an intermediate value 

between the two ranges (i.e., 1.5), rather 

than focus on either the highest or 

lowest values, which is not the most 

conservative assumption that the EPA 

could have made. This study 167 also 

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, the EPA 

disagrees that these studies considered 

collectively contradict the cooking loss 

factor in the analysis. Specifically, the 

first study 168 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,169 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.170 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 study 171 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 

study 172 only addressed the issue 

qualitatively, thus cannot be used for 

the cooking loss factor. When 

considered collectively, the EPA 

disagrees that the additional studies 

identified by the commenter contradict 

the cooking loss factor used in the risk 

assessment and maintains that the 

Morgan study 173 remains the most 


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174Burger et al., 2002. 

175 Id. 

176Shilling, Fraser, Aubrey White, Lucas Lippert, 

Mark Lubell (2010). Contaminated fish 

consumption in California’s Central Valley Delta. 

Environmental Research 110, p. 334–344. 

177 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. 

178Personal communication, Dr. Dellinger, 

September 27, 2011. 

179U.S. EPA. 1991. Risk Assessment Guidance for 

Superfund (RAGS). Part C 1991 EPA/9285.7–01C. 

October. 

180U.S. EPA. 2000. National Guidance: Guidance 

for Assessing Chemical Contaminant Data for Use 

in Fish Advisories, Volume 2. EPA 823–B–00–008, 

November. 

181U.S. EPA. 1989. Risk Assessment Guidance for 

Superfund (RAGS). EPA/540/1–89/002. December. 

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).174 Therefore, the EPA 

interprets the fish consumption rates 

provided in this study 175 as 

representing as cooked/prepared and 

not for raw fish and for that reason, 

application of a preparation/cooking 

adjustment factor is required. Another 

study 176 used different sized models of 

cooked fish filets and therefore these 

consumption rates are also interpreted 

as represented as cooked/prepared and 

not raw fish. One study 177 178 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.179 180 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 exposure (‘‘RME’’) 

scenario,181 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 national-scale, 

included a limited number of 

individuals living in diverse and 

localized areas. 

One commenter stated that the 

assumption with the greatest impact on 

risk is the fish consumption rate. That 

same commenter stated that using 99th 

percentile ingestion rate dramatically 

increases HQ and IQ loss compared to 

the 50th percentile ingestion rate. The 

commenter stated that when an estimate 

of the 95th percentile ingestion rate of 

the 15 to 44 year old female population 

is considered, the HQ is a tenth of the 

value computed with the 99th 

percentile high-end female fisher. 

One commenter stated that EPA 

provides broad summary statistics of its 

fish tissue data in Table 5–2 of the 

Regulatory Impact Analysis (RIA), but 

the summary does not allow an 

assessment of the representativeness 

and robustness of the underlying data 

for the risk assessment, especially at the 

tails of the distribution. The commenter 

stated that the table does not include a 

median statistic and does not provide 

any information on the number of lakes 

and river segments in each watershed. 

According to the commenter, an 

analysis of EPA’s database by the SAB 

indicated that 60 percent of the 

watersheds with fish Hg data from rivers 

have risks calculated based upon a 

sample size of one or two fish. The 

commenter stated that it is not 

reasonable to base a significant policy 

and regulation decision on watersheds 

where exposure is based on a single fish 

sample in a single water body within it. 

Several commenters criticized EPA’s 

use of the 75th percentile fish tissue 

MeHg level in a watershed. One 

commenter stated that EPA provided no 

rationale for its decision to choose the 

highest of the 75th percentile for fish Hg 

levels among rivers and lakes within the 

HUC. Several commenters stated that 

subsistence fishers are less likely to 

target larger fish relative to recreational 

fishers. Several commenters suggested 

that EPA include a sensitivity analysis 

using the mean or median fish MeHg 

level in a watershed. One commenter 

also stated that EPA arbitrarily inflated 

the risk estimates by assuming 

consumption of only fish greater than 7 

inches and choosing the largest of the 

75th percentile of fish Hg levels from 

these larger fish (i.e., larger than 7 

inches) for rivers and lakes. That same 

commenter suggested using the median 

of all size fish, not just those over 7 

inches. 

One commenter stated that EPA 

should quantify adverse effects from the 

ingestion of MeHg in seafood in 

addition to ingestion of MeHg from selfcaught 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. 

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. EGUattributable Hg risk, which are 

subsistence fishing populations active at 

inland freshwater lakes and rivers. 

Specifically, within that subsistence 

fishing population, the EPA is interested 

in those individuals who are most atrisk, which includes those who 

consume the most fish. For that reason, 

the EPA considered a range of high-end 

fish consumption rates including the 

99th percentile representing the most 

highly-exposed individuals. In 

responding to the SAB peer review, the 

EPA clarified this focus in the 


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182Burger et al., 2002. 

183Burger, 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. 

184Burger, 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. 

185California 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. 

186Tai, S. 1999. ‘‘Environmental Hazards and the 

Richmond Laotian American Community: A Case 

Study in Environmental Justice.’’ Asian Law Journal 

6: 189. 

187Corburn, J. 2002. ‘‘Combining communitybased research and local knowledge to confront 

asthma and subsistence-fishing hazards in 

Greenpoint/Williamsburg, Brooklyn, New York.’’ 

Environmental Health Perspectives 110(2). 

188Burger et al., 1999a. 

189Burger et al., 1999b. 

190CalEPA, 1997. 

191Tai, 1999. 

192Corburn, 2002. 

193U.S. EPA–SAB, 2011. 194U.S. EPA–SAB, 2011. 

introduction to the revised Hg Risk TSD 

and changed the full title to revised 

Technical Support Document: NationalScale Assessment of Mercury Risk to 

Populations with High Consumption of 

Self-caught Freshwater Fish. 

The EPA agrees that the fish 

consumption rate is an important factor 

in calculating risk from exposure to 

MeHg in fish. The EPA acknowledges 

that the distribution of fish 

consumption rates is positively skewed, 

which means that at higher percentiles 

(e.g., 90th, 95th, and 99th) there is a 

substantial increase in ingestion rates 

relative to the mean or median. The 

revised Hg Risk TSD includes a 

reasonableness check on the amount of 

fish consumed (as a daily value) 

reflected in the different rates. While the 

99th percentile consumption rates for 

the subsistence female fisher (373 g/day) 

is substantially higher than the 90th or 

95th percentile values (123 and 173 g/ 

day respectively), the 99th percentile 

value translates into a 13-ounce meal. 

While this represents a large serving, it 

is still reasonable if representing an 

individual who receives all of their meat 

protein from self-caught fishing, and the 

13 ounces per day do not have to be 

eaten all at one meal. The higher 

consumption rates (i.e., greater than 250 

g/day) are supported by all three studies 

used in the risk assessment, and 

therefore, there is support across studies 

near the upper bound of likely 

consumption rates in this range. The 

EPA acknowledges uncertainty 

associated with estimating high-end 

percentile values in these studies due to 

relatively low sample sizes for some 

population groups. However, even if a 

few individuals reported these high selfcaught fish consumption rates, making 

it difficult to characterize the 

population percentiles they represent, 

the values still suggest that these levels 

of high fish consumption exist among 

surveyed individuals. To determine 

whether a public health hazard could 

exist, the EPA asserts that it is 

reasonable to include these 

consumption rates as representative of 

the most at-risk populations. In these 

cases, however, the EPA acknowledges 

that it is important to highlight 

uncertainty associated with 

characterizing the specific population 

percentile that these ingestion rates 

represent, and EPA has done so in the 

revised Hg Risk TSD. 

The EPA disagrees with the comment 

that high consumption rates are poorly 

documented. Evidence of these high fish 

consuming populations can be found in 

surveys 182 and specialized 

studies.183 184 185 186 187 Several studies 

identified additional fishing 

populations with subsistence or near 

subsistence consumption rates, 

including urban fishing populations 

(including low-income 

populations),188 189 190 Laotian 

communities,191 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.192 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.193

The EPA agrees that the Hg Risk TSD 

would be improved by clarifying that 

the literature review focused on 

identifying studies that characterize 

subsistence fish consumption for groups 

active at freshwater locations within the 

U.S., and EPA has revised the Hg Risk 

TSD accordingly. In the Hg Risk TSD, 

the EPA summarized important study 

attributes for the source studies used to 

obtain fish consumption rates. This 

information was provided in Table C–1 

in an appendix. To improve clarity, the 

EPA moved the summary table to the 

main body in the revised Hg Risk TSD. 

In identifying these studies, the EPA 

focused on surveys for subsistence 

fishers that were applicable at the 

broader regional or national level. In the 

Hg Risk TSD, the EPA acknowledged 

the smaller sample sizes for some of the 

subsistence fisher groups, and in several 

cases the EPA did not use the 99th 

percentile consumption rates because 

the sample sizes were too low to 

support this level of resolution. This 

decision did not affect EPA’s finding of 

a hazard to public health, which is 

based on the results for the female 

subsistence fishing population, which 

has an estimate of the 99th percentile 

consumption rate that is supported by 

an adequate sample size. 

The EPA disagrees with the comment 

that it did not provide a rationale for 

choosing the 75th percentile fish tissue 

concentration across lakes and rivers in 

a watershed. However, the EPA 

modified the methodology based on 

evaluation of the number of samples 

within each watershed (responding to a 

recommendation from the SAB). In the 

revised methodology, the EPA computes 

the 75th percentile value at each 

sampling site within a watershed. The 

EPA then computed the average of the 

site-specific 75th percentile fish tissue 

Hg values within a given watershed. 

This approach does not differentiate 

between rivers and lakes and reflects an 

improved treatment of behavior, 

allowing for fishers to choose among 

multiple fishing sites within a 

watershed. 

The EPA generally agrees with the 

comment that some fraction of 

subsistence fishers likely consume fish 

without consideration for size (given 

dietary necessity), however, the EPA 

considers it reasonable to assume that a 

subset of subsistence fishers could target 

larger fish in order to maximize the 

potential consumption per unit of 

fishing effort. The EPA uses this subset 

of subsistence fishers targeting larger 

fish, which is represented by the 75th 

percentile fish tissue value, in the risk 

assessment. In addition, including the 

female subsistence fishing population in 

the analysis also provides coverage for 

high-end recreational anglers who target 

larger freshwater fish. The SAB 

commented that: ‘‘Using the 75th 

percentile of fish tissue values as a 

reflection of consumption of larger, but 

not the largest, fish among sport and 

subsistence fishers is a reasonable 

approach and is consistent with 

published and unpublished data on 

predominant types of fish 

consumed.’’ 194 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 


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9350 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

195Pennsylvania Fish and Boat Commission. 

2011. Summary Book: 2011 Pennsylvania Fishing 

Laws & Regulations available at: http:// 

fishandboat.com/fishpub/summary/inland.html. 196U.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. 197NAS, 2000. 

198Budtz-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. 

199 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). 

200Wieslaw 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. 

201 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. 

202Hibbeln 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: 

populations potentially at-risk from U.S. 

EGU-attributable MeHg exposures. In 

the revised Hg Risk TSD, the EPA 

clarified that the 7-inch cutoff 

represents a minimum size limit for a 

number of key edible freshwater fish 

species established at the State-level. 

For example, Pennsylvania establishes 7 

inches as the minimum size limit for 

both trout and salmon (other edible fish 

species such as bass, walleye and 

northern pike have higher minimum 

size limits).195

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 RfD 196 is based on sound 

science, which was supported by the 

findings of the NAS Study,197 and that 

EPA appropriately applied the RfD in 

the Hg risk assessment. The commenters 

also stated that recent studies find clear 

associations between maternal blood Hg 

levels and delayed child development 

and cardiovascular effects, as well as 

potential for effects due to exposure to 

pollutant mixtures including lead. 

However, many commenters 

expressed concerns regarding EPA’s use 

of the MeHg RfD as a benchmark for 

health risk. Several commenters raised 

concerns claiming that EPA has not 

incorporated the best available Hg 

toxicological data into the RfD, which 

results in a flawed analysis and an 

overestimate of the impact of Hg 

emissions on human health. 

Several commenters stated that, when 

deriving the RfD, the EPA relied on the 

flawed Faroe Islands’ children study 

and ignored the Seychelles Islands 

study,198 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 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,199 and Poland.200

One commenter criticized EPA for 

using a linear dose-response 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 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) 201 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 

uncertainty, including uncertainty in 

the RfD, uncertainty in extrapolating a 

dose-response relationship between 

MeHg exposure and change in IQ, 

uncertainty in extrapolating the doseresponse 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 

study202 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 intraindividual variation in IQ are higher 

than the threshold. 

Several commenters question the 

relationship between cardiovascular 

effects and MeHg exposure. Two 


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203Roman HA, Walsh TL, Coull BA, Dewailly E ́, 

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. 

204 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. 

205 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. 

206 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. 

207Hallgren 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. 

208Mozaffarian, Dariush. 2011. ‘‘Mercury 

Exposure and Risk of Cardiovascular Disease in 

Two U.S. Cohorts,’’ N Engl J Med 364: 1116–1125. 

209Hibbeln et al., 2007. 

210Mozaffarian, et al., 2011. 

211NAS, 2000. 

212U.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. 

213U.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/aqlife/pollutants/methylmercury/index.cfm. 

214U.S. EPA–IRIS, 2001. 

215Rice 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. 

216NAS, 2000. 

217 Id. 

218U.S. EPA, 2001b. 

219U.S. EPA–IRIS, 2001. 

220Schober 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. 

221Mahaffey, 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. 

commenters cited studies examining the 

relationship between MeHg exposure 

and cardiovascular 

effects,203 204 205 206 207 208 but concluded 

that it seems premature to use these 

studies to establish a dose-response 

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.209 210 One 

commenter noted the important 

protective role of dietary selenium 

against MeHg toxicity because the 

binding affinity of Hg to Se is much 

higher than binding to sulfur. 

Response: The EPA agrees with 

commenters that state the MeHg RfD is 

the appropriate health value for 

determining elevated risks from MeHg 

exposure and disagrees with 

commenters that state otherwise. At this 

time, the EPA is neither reviewing nor 

revising its 2001 RfD for MeHg. The 

2001 RfD for MeHg is EPA’s current 

peer-reviewed RfD, which is the value 

EPA uses in all its risk assessments. The 

EPA’s RfD is based on multiple 

benchmark doses, and RfDs were 

calculated on various endpoints using 

the three extant large studies of 

childhood effects of in utero exposure: 

Faroe Islands, New Zealand, and an 

integrative measure including data from 

Seychelles. The EPA did not choose to 

base the MeHg RfD solely on results 

from the Seychelles Islands, as both the 

NAS 211 and an independent scientific 

review panel convened as part of the 

IRIS process 212 advised strongly against 

using results from a study that at the 

time had not shown an association 

between MeHg exposure and adverse 

effects. Further, the EPA disagrees with 

comments stating that EPA based the 

MeHg RfD solely on results from the 

Faroe Islands population and disagrees 

that the information underlying the RfD 

is ‘‘poorly explained’’. The EPA has 

provided detailed documentation for the 

choices underlying calculation of the 

RfD.213 214 215 To correct a 

misunderstanding by the commenter, 

the data underlying the Faroe Islands 

study have been previously published 

in the peer reviewed literature. 

The EPA disagrees that it did not 

incorporate the latest Hg data to support 

the appropriate and necessary finding. It 

is the policy of EPA to use the most 

current peer reviewed, publicly 

available data and methodologies in its 

risk assessments. However, the EPA 

noted in the preamble to the proposed 

rule that ‘‘data published since 2001 are 

generally consistent with those of the 

earlier studies that were the basis of the 

RfD, demonstrating persistent effects in 

the Faroe Island cohort, and in some 

cases associations of effects with lower 

MeHg exposure concentrations than in 

the Faroe Islands. These new studies 

provide additional confidence that 

exposures above the RfD are 

contributing to risk of adverse effects, 

and that reductions in exposures above 

the RfD can lead to incremental 

reductions in risk.’’ However, the EPA 

has not completed a comprehensive 

review of the new literature, and as 

such, it would be premature to draw 

conclusions about the overall 

implications for the RfD. 

The EPA agrees that EPA’s RfD is not 

the same as the levels used by other 

federal agencies. In their advice to the 

EPA on the appropriate bases for a 

MeHg RfD, NAS specifically 

recommended that EPA use neither the 

study nor the uncertainty factor 

employed by the Agency for Toxic 

Substances Disease Registry (ATSDR) in 

the calculation of the minimal risk 

level.216

The EPA disagrees that the 

uncertainty factor is ‘‘unusually high’’. 

The uncertainty factor used in 

calculation of EPA’s peer-reviewed 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 NAS 217 and an 

independent panel of scientific peer 

reviewers convened as part of the IRIS 

process.218

The IRIS makes this statement 

regarding a threshold for MeHg, ‘‘It is 

also important to note that no evidence 

of a threshold arose for methylmercuryrelated 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 models, K 

= 1 provided a better fit for the endpoint 

models than did higher values of K.’’ 219

The EPA disagrees that it is using the 

MeHg RfD as an absolute bright line for 

health effects in the risk assessment. As 

stated in the preamble to this proposed 

rule, the RfD is an estimate of a daily 

exposure to the human population that 

is likely to be without an appreciable 

risk of deleterious effects during a 

lifetime. The EPA also stated that no 

RfD defines an exposure level 

corresponding to zero risk. Because 

mercury is a cumulative neurotoxin, it 

is important to distinguish health effects 

from public health hazard. Within the 

context of the appropriate and necessary 

finding, we interpret a public health 

hazard as risk, rather than certain 

occurrence of health effects. 

The EPA disagrees that exposure 

levels in the U.S. are lower than those 

in the Faroe Islands study. Exposure to 

MeHg in the U.S. has been reported at 

the same levels as those published in 

the Faroe Islands.220 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 (mg/L) in the Northeast U.S. and 7.2 

mg/L in coastal areas.221 Higher levels 

have been reported among subjects 

known to consume fish. For example, 

one study reported mean blood Hg for 

adult women to be 15 mg/L; range for 


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9352 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

222Hightower Jane M, Moore Dan. Mercury levels 

in high-end consumers of fish. Environ Health 

Perspect. 2003 Apr; 111(4): 604–608. 223Oken, 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. 

224Lederman, 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. 

225Hisamichi 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. 

226Sunderland 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. 

227Mahaffey, 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. 

228Tran, N.L., L. Barraj, et al., 2004. ‘‘Combining 

food frequency and survey data to quantify longterm dietary exposure: a methyl mercury case 

study.’’ Risk Anal 24(1): 19–30. 

229 Id. 

230Miranda, 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. 

231Hightower and Moore, 2003. 

232Hightower, 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. 

233McKelvey, 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. 

234Hightoweret al., 2006. 

235NAS, 2000. 

236U.S. EPA, 2001a. 

237National 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. 

238NAS, 2000. 

239Budtz-J<rgensen, E., N. Keiding, and P. 

Grandjean. 1999. Benchmark modeling of the 

Faroese methylmercury data. Final Report to U.S. 

EPA. 

240 DSHA, 2005. 

241U.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. 

242U.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. 

243U.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. 

244U.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. 

men and women was 2 to 89.5 mg/L.222

Note that some publications have 

reported Hg effects in U.S. populations 

at or below the current U.S. RfD.223 224

Also, the EPA disagrees with the 

commenter stating all ocean fish 

throughout the world contain about the 

same amount of MeHg. Marine fish in 

commerce differ widely in Hg 

concentration by species, and fish 

within the same species but caught at 

different locations have variable 

amounts of Hg in their tissues.225 226

The EPA disagrees that there is a 

statistically discernible downward trend 

in the NHANES data on blood Hg. The 

EPA is unaware that a formal statistical 

analysis for temporal trends has been 

completed for NHANES data on blood 

Hg levels for the period 1999 to 2008. 

Mahaffeyet 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.’’ 227 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 this level. One study 

estimated very high blood Hg levels at 

the 99th percentile for females of childbearing age.228 Other published studies 

have shown that various population 

groups can have high blood Hg 

levels.229 230 231 232 233 For example, one 

study found that 83 percent of the 

NHANES Asian population exceeded 

the RfD-equivalent blood mercury 

level.234

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.235 The EPA also 

documented the independence of PCB 

and MeHg effects in the Faroe Islands 

population.236 The National Institute of 

Environmental Health Sciences (NIEHS) 

concluded that both PCB and Hg had 

adverse effects.237 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.238 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.239 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.240 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 above 

the benchmark dose level (BMDL) of 5.8 

mg/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.241 242 243 244 The Agency’s 

concern with the likelihood of human 

exposure to multiple contaminants is 


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245U.S. EPA–SAB, 2011. 

246U.S. EPA–SAB, 2011. 

247U.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/ 

989B57DCD436111B852572AC0079DA8A/$File/ 

casac-07–003.pdf. 

248U.S. EPA–SAB, 2011. 

249Axelrad, 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. 

250Bellinger 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. 

251U.S. EPA–SAB, 2011. 

252Bellinger, 2005. 

253U.S. EPA–SAB, 2011. 

254 76 FR 25001. 

255Oken et al., 2008. 

256Lederman et al., 2008. 

257Suzuki, 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. 

reflected in the multi-chemical scope of 

the rulemaking. However, the EPA 

focused the technical analyses 

supporting the proposed regulation on 

effects of individual pollutants rather 

than cumulative effects. 

The EPA disagrees with commenters 

suggesting that the RfD-based 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.’’ 245

The SAB also recommended that EPA 

revise the Hg Risk TSD to include 

additional qualitative discussion about 

uncertainty in the revised Hg Risk TSD. 

Specifically, the SAB recommended that 

EPA revise the Hg Risk TSD ‘‘to better 

explain the methods and choices made 

in the analysis, and analytical results, 

and where the uncertainties lie.’’ The 

SAB noted several uncertainties related 

to the RfD. The EPA agrees with this 

recommendation and included a more 

complete discussion of these 

uncertainties in the revised Hg Risk 

TSD. 

The EPA disagrees that the IQ metric 

threshold is questionable. The SAB 

concluded that it was reasonable to 

consider a loss of >1 or >2 IQ points a 

public health concern. The SAB stated, 

‘‘The Panel agreed that if IQ loss is 

retained in the risk assessment despite 

these reservations, a loss of one or two 

points would be an appropriate 

benchmark.’’ 246 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).247 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.’’ 248 As noted in 

other studies,249 250 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. 

Although EPA disagrees that the IQ 

results are too uncertain to rely upon, 

the EPA acknowledges that IQ is not the 

most sensitive neurodevelopmental 

endpoint affected by MeHg exposure, as 

also noted by the SAB. The SAB 

recommended that the IQ analyses be 

retained but be de-emphasized in the 

documentation underlying the final 

regulation. The SAB concluded, ‘‘The 

Panel does not consider it appropriate to 

use IQ loss in the risk assessment and 

recommended that this aspect of the 

analysis be de-emphasized, moving it to 

an appendix where IQ loss is discussed 

along with other possible endpoints not 

included in the primary assessment. 

While the Panel agreed that the 

concentration-response function for IQ 

loss used in the risk assessment is 

appropriate, and no better alternatives 

are available, IQ loss is not a sensitive 

response to methylmercury and its use 

likely underestimates the impact of 

reducing methylmercury in water 

bodies.’’ 251 The EPA is following the 

SAB’s recommendation by 

deemphasizing the IQ analysis and 

placing that analysis in an appendix to 

the revised Hg Risk TSD. 

The SAB, however, supported the use 

of the IQ dose-response function 

calculated by EPA in the Hg Risk TSD. 

The SAB noted, ‘‘The function used 

came from a paper by Axelrad and 

Bellinger (2007) that seeks to define a 

relationship between methylmercury 

exposure and IQ. A whitepaper by 

Bellinger (Bellinger, 2005) 252 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.’’ 253

The EPA disagrees that the Agency 

has overstated or failed to review the 

scientific literature on cardiovascular 

effects from MeHg exposure. As 

summarized in the preamble to the 

proposal, the EPA stated that the NAS 

study concluded that ‘‘Although the 

data base is not as extensive for 

cardiovascular effects as it is for other 

end points (i.e., neurologic effects) the 

cardiovascular system appears to be a 

target for MeHg toxicity in humans and 

animals.’’ 254 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 effects, and there is 

inconsistency among available studies 

as to the association between MeHg 

exposure and various cardiovascular 

system effects. In the future, the EPA 

may update the MeHg RfD and will 

review all of the relevant scientific 

literature available at that time, 

including data on all relevant 

endpoints, and weight of evidence for 

likelihood that MeHg produces specific 

effects in humans. 

The EPA acknowledges the research 

regarding the effectiveness of fish 

advisories. However, the proposed 

regulation does not address the subject 

of fish advisories, consumer advice on 

fish or efficacy of such advice. The EPA 

rejects the commenter’s speculation 

regarding whether the estimated IQ 

impacts for the regulation are real. 

Adverse effects of in utero Hg exposure 

have been reported in populations in 

the U.S.255 256 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.257

That study suggests that at normal 

Japanese dietary intake of MeHg and 

fish nutrients, the overall effect is 

adverse. While Japanese fish 

consumption and Hg exposure are both 

somewhat higher than the mean U.S. 

exposure, these levels are still within 

the distribution of U.S. consumers. 


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258 Grandjean P, Bjereve K, Wihe P, and 

Sterewald u. 2001a. ‘‘UBirthweight in a fishing 

community: significance of essential fatty acids and 

marine food contaminants.’’ In. J. Epidemiol. 

30:1272–1278. 

259Budtz-Jorgensen, E.; Grandjean, P.; Weihe, P. 

2007. ‘‘Separation of risks and benefits of 16 

seafood intake.’’ Environmental Health 

Perspectives. Vol. 115, 323–327. 

260Choi et al., 2008a. 

261Choi et al., 2008b. 

262Oken et al., 2008. 

263Strain, 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. 

264Suzuki, et al., 2007. 

265Oken et al., 2008. 

266Choi 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. 

267Choi AL, Budtz-J<rgensen E, J<rgensen 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. 

268U.S. EPA–SAB, 2011. 269 Id. 

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.258 259 260 261 262 263 264 Recent 

studies 265 266 267 and analyses indicate 

the potential for nutrients in fish 

(particularly marine fish) to mask some 

of the observed adverse effects of MeHg. 

Because EPA did not adjust for potential 

confounding by nutrients in marine fish 

and mammals, the benchmark doses 

used in the RfD derivation may be 

underestimated. 

The EPA recognizes the potential for 

confounding of the effects of Hg on the 

developing nervous system by a range of 

nutrients and discusses this uncertainty 

in the revised Hg Risk TSD. Regarding 

selenium, the SAB commented that 

‘‘one SAB member suggests the use of 

blood markers of selenium-dependent 

enzyme function, noting that 

methylmercury irreversibly inhibits 

selenium-dependent enzymes that are 

required to support vital-but-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.’’ 268 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.’’ 269

6. General Comments on Hg Risk 

Assessment 

Comment: Several commenters 

generally supported the Hg risk 

assessment, but several other 

commenters generally disagreed with 

the Hg risk assessment. One supporter 

stated that EPA reasonably determined 

that Hg emissions pose a public health 

hazard, correctly requested peer review 

of Hg risk analysis and correctly 

concluded EGU-attributable MeHg poses 

a hazard to public health at watersheds 

when considering all sources of Hg 

deposition and U.S. EGUs alone. Two 

commenters noted that the contribution 

of U.S. EGUs to total Hg deposition can 

significantly contribute to hundreds of 

watersheds, and U.S. EGU deposition 

alone may endanger sensitive 

populations near many of these 

watersheds. 

Several commenters claimed that 

overly conservative assumptions in the 

risk analysis render the results flawed 

and unreliable, including using CMAQ 

to model deposition, Mercury Maps, 

fish consumption rate and fish MeHg 

concentrations, overly stringent RFD, 

national-scale model, using poverty as a 

surrogate for subsistence fishing, 

assuming a subsistence fisher resides in 

most watersheds with fish tissue data, 

fishers only eat larger fish with high Hg 

concentrations, cooking loss adjustment, 

unrealistically high fish ingestion rates 

(a large fish meal every day), focused on 

the extremes of the distributions, cast 

many assumptions as an underestimate 

of the effect despite evidence to the 

contrary, and created inappropriate 

metrics for risk that show no 

improvement despite significant Hg 

emissions reductions in the U.S. 

Several commenters cite Tetra Tech’s 

analysis that assessed Hg risk using 

different consumption rates, cooking 

factor, mean fish tissue concentrations, 

and EGU-attributable Hg deposition 

only, which showed considerably fewer 

watersheds that exceed an HQ of 1 at 

2016 deposition levels. 

Several commenters claim that this 

regulation would not significantly 

reduce Hg exposure via fish 

consumption because EGU-attributable 

deposition is a small fraction of total 

deposition. One commenter stated that 

EPA’s data shows Hg emissions from 

U.S. EGUs have little influence on fish 

Hg concentrations despite a reduction of 

41 tons of Hg in the U.S. between 2005 

and 2016. One commenter requested 

that EPA accurately describe the low 

health risks posed by utility hazardous 

air pollutant emissions. One commenter 

stated that EPA did not consider 

scientific information showing that 

there is no straightforward connection 

between Hg emissions from U.S. EGUs 

to the Hg level in fish, which is 

dependent upon many environmental 

factors, such as sunlight and organic 

matter, pH, water temperature, sulfate, 

bacteria, and zooplankton present in the 

ecosystem. One commenter stated that 

there is not any demonstrable evidence 

that anyone in the U.S. has suffered 

adverse health problems as a result of 

Hg emissions from coal-fired 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 

nation-wide representativeness of the 

fish tissue data. 

One commenter stated the subset of 

watersheds considered in the analysis 

(i.e., with fish tissue data) have clearly 

higher U.S. EGU-attributable deposition 

than the distribution of all watersheds. 

One commenter stated EPA’s 

reporting of IQ point loss is erroneous 

and not relevant to informing policy, 

and the U.S. EGU contribution to risk is 

marginal as evidenced by the null 

values for the 50th percentile 

watershed. 

One commenter notes that U.S. EGUattributable emissions of Hg have 

decreased significantly between 2005 


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270U.S. EPA–SAB, 2011. 

271 Id. 

272 Id. 

273 Id. 

and 2016, but claims that this decrease 

does not appear to affect the risk results. 

Response: The purpose of the Hg risk 

assessment is not to assess the 

magnitude of risk reduction under the 

proposed rule, but rather to estimate the 

magnitude of absolute risk attributable 

to U.S. EGUs currently and following 

implementation of other applicable 

CAA requirements. That said, any 

potential risk reductions following 

implementation of the MACT rule itself 

would likely reflect a number of factors 

besides the national average U.S. EGU 

deposition value cited by the 

commenter. These additional factors 

include: (a) Spatial gradients in the 

magnitude of absolute U.S. EGUattributable 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. EGU-attributable 

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.’’ 270 Furthermore, the SAB 

concluded, ‘‘The SAB regards the design 

of the risk assessment as suitable for its 

intended purpose, to inform decisionmaking 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.’’ 271

Although the SAB did indicate 

difficulty in evaluating the risk 

assessment based solely on the Hg Risk 

TSD, the panel obtained additional 

information from EPA through the peer 

review process and determined that 

‘‘the SAB supports the overall design of 

and approach to the risk assessment and 

finds that it should provide an objective, 

reasonable, and credible determination 

of the potential for a public health 

hazard from mercury emitted from U.S. 

EGUs.’’ 272 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.’’ 273 The EPA has revised the Hg 

Risk TSD as part of the final rulemaking 

to address the SAB’s recommendations 

and has made that revised Hg Risk TSD 

available in the rule docket. 

The SAB concurred with EPA’s 

analytical assumptions and overall 

study design for the Hg Risk TSD, 

including the RfD-based HQ approach, 

fish tissue data, 75th percentile size 

fish, Mercury Maps assumption, and 

consumption rates. Based on the SAB 

peer review, the EPA strongly disagrees 

with commenter statements that the 

results reported in the Hg Risk TSD are 

unreliable, overly conservative, extreme, 

inconsistent with EPA risk guidelines, 

or severely overstate risk based on the 

stated objectives of the analysis. The 

EPA has specifically addressed each of 

these assumptions in the previous 

sections of the preamble, and thus, does 

not repeat those responses here. Based 

on the review by the SAB, the EPA has 

accurately described the health risks 

posed by utility hazardous air pollutant 

emissions and disagrees with the 

commenter’s statement that EPA has not 

provided any demonstrable evidence to 

show that adverse health risks exist. The 

EPA has applied peer reviewed 

modeling to estimate the deposition of 

Hg attributable to U.S. EGUs. The EPA 

asserts that these metrics demonstrate a 

clear hazard to public health from Hg 

emissions from U.S. EGUs. 

The EPA thoroughly evaluated the 

Tetra Tech analysis. The EPA does not 

agree that the analysis by Tetra Tech 

uses assumptions that are ‘‘more 

reasonable’’, and the SAB agreed that all 

of EPA’s assumptions in the Hg Risk 

TSD are reasonable and appropriate. 

The EPA asserts that Tetra Tech’s 

analysis does not fully cover subsistence 

fishers likely to experience elevated 

U.S. EGU-related Hg exposure. 

Specifically, the risk estimate cited in 

the comment reflects application of a 

number of behavioral assumptions that 

provide significantly less coverage for 

higher risk subsistence fishers. Fish 

consumption surveys cited in the 

revised Hg Risk TSD suggest that higher 

percentile subsistence fishers eat more 

than twice the level of fish assumed by 

Tetra Tech. Tetra Tech’s analysis also 

used the median fish tissue levels, but 

it is reasonable to assume that 

subsistence fishers would target 

somewhat larger fish to maximize the 

volume of edible meat per unit time 

spent fishing. Tetra Tech’s analysis also 

assumed that cooking fish did not 

concentrate Hg, but a number of studies 

discussed in the revised Hg Risk TSD 

explicitly provide adjustment factors 

involving a higher unit concentration 

following preparation. Taken together, 

Tetra Tech’s analysis does not address 

the stated goal of the risk assessment to 

assess the nature and magnitude of risk 

for those individuals likely to 

experience the greatest risk associated 

with exposure to U.S. EGU-attributable 

Hg. 

The EPA disagrees with the 

commenter’s assertion that this rule will 

not affect risks associated with Hg 

exposure. Hg from U.S. EGUs 

contributes to the levels of MeHg in fish 

across the country and consumption of 

contaminated fish can lead to increased 

risk of adverse health effects. The EPA 

has shown in the RIA (Chapter 5) that 

this rule will reduce Hg levels in fish. 

The EPA acknowledges that U.S. 

EGUs contribute only a small fraction of 

total Hg deposition in the U.S. However, 

U.S. EGUs remain the largest emitter of 

Hg in the U.S., and the revised Hg Risk 

TSD shows that U.S. EGU-attributable 

Hg deposition results in up to 29 

percent of modeled watersheds with 

populations potentially at-risk. Our 

analyses show that of the 29 percent of 

watersheds with population at-risk, in 

10 percent of those watersheds U.S. 

EGU deposition alone leads to potential 

exposures that exceed the MeHg RfD, 

and in 24 percent of those watersheds, 

total potential exposures to MeHg 

exceed the RfD and U.S. EGUs 

contribute at least 5 percent to Hg 

deposition. Mercury risk is increasing 

for exposures above the RfD, and as a 

result, any reductions in Hg exposures 

in locations where total exposures 

exceed the RfD can result in reduced 

risks. While these reductions in risk 

may be small for most populations and 

locations, in some watersheds and for 

some populations, reductions in risk 

may be greater. 

The SAB also directly addressed the 

question of the nation-wide 

representativeness of the fish tissue 

MeHg data in the national Hg risk 

assessment. The SAB concluded, 

‘‘Although the SAB considers the 

number of watersheds included in the 

assessment adequate, some watersheds 


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274U.S. EPA–SAB, 2011. 

275Orihel et al., 2007. 

276Orihel et al., 2008. 

277Harris et al., 2007. 

in areas with relatively high mercury 

deposition from U.S. EGUs were undersampled 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.’’ 274 In response to 

the SAB’s recommendations, the EPA 

obtained additional fish tissue sample 

data from several states, particularly 

Pennsylvania, Wisconsin, Minnesota, 

New Jersey, and Michigan. This 

additional data increased the total 

number of watersheds assessed in the 

analysis by 33 percent nationally. In 

Florida, the EPA assessed the Hg-related 

health risk for 40 watersheds. Because 

EPA did not find any additional fish 

tissue data for watersheds in Florida 

that could be incorporated into the 

analysis, the total number of watersheds 

in Florida assessed in the revised Hg 

Risk TSD remains the same as the Hg 

Risk TSD at proposal. 

The EPA disagrees with the 

commenter that there were errors in the 

Hg Risk TSD. Instead, the commenter 

has misinterpreted how EPA calculated 

the percentiles. The percentile (and 

mean) values presented in Table ES–1 

for total and U.S. EGU-attributable Hg 

deposition are not matched by 

watershed. In other words, the EPA 

queried for the percentiles (and mean) 

provided for total Hg deposition and 

presented those percentiles and then 

separately estimated the percentiles for 

U.S. 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, 

the EPA acknowledges that total Hg fish 

tissue levels are not correlated with 

levels of total Hg deposition when 

looking across watersheds because this 

relationship is highly dependent on the 

methylation potential at the specific 

waterbody, which is affected by pH, 

sulfate deposition, turbidity, etc. 

However, several recent studies 275 276 277

show, and the SAB agrees, that it is 

appropriate for EPA to assume that 

changes in Hg deposition are linearly 

associated with changes in fish tissue 

concentration. In addition, the EPA 

agrees that the subset of watersheds in 

the risk analysis have somewhat higher 

U.S. EGU deposition than the 

distribution of all watersheds, but EPA 

disagrees that oversampling of high 

deposition watersheds is inappropriate. 

The EPA does not agree that there is 

no improvement in fish Hg 

concentrations between 2005 and 2016, 

or that there will be no further 

improvement from decreasing Hg 

emissions from U.S. 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, nonU.S. Hg emissions. U.S. EGUs remain 

the largest source of Hg emissions in the 

U.S., and reductions in those emissions 

will result in reduced Hg deposition in 

many highly impacted watersheds. As 

shown in the revised Hg Risk TSD, 

average U.S. EGU-attributable fish tissue 

Hg concentrations is estimated to 

decrease by 44 percent between 2005 

and 2016. Although we did not remodel 

risk for the 2005 scenario in the revised 

Hg Risk TSD, we estimated at proposal 

that the total percent of modeled 

watersheds with populations potentially 

at-risk from Hg emissions from U.S. 

EGUs exceeding either risk metric (i.e., 

U.S. EGUs alone or total potential 

exposures to MeHg exceed the RfD and 

U.S. EGUs contribute at least 5 percent) 

would decline from 62 percent in 2005 

to 28 percent in 2016. This projected 

decline is primarily due to a 

combination of additional pollution 

control technologies installed to comply 

with federal regulations, such as 

CSAPR, and changing fuels, such as the 

shift to natural gas. 

The EPA disagrees that IQ loss is 

erroneous or irrelevant to informing 

policy, but EPA has moved that analysis 

to an appendix in the revised Hg Risk 

TSD, per the SAB’s recommendation. 

The EPA disagrees that the IQ effects at 

the 50th 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. EGUattributable Hg. 

We also disagree with those 

commenters that point to the SAB’s 

statements concerning the clarity of the 

Hg Risk TSD to suggest that the public 

did not have an ample opportunity to 

comment on the Hg risk assessment. 

Although it is correct that the SAB said 

the Hg Risk TSD was difficult to 

evaluate until EPA staff explained it at 

the public meeting in June 2011, we 

note that the commenters that assert that 

this issue amounts to a violation of CAA 

section 307(d) notice requirements 

made detailed technical comments, 

including many of the same comments 

as the SAB. Furthermore, the EPA 

provided notice of the peer review in 

the preamble to the proposed rule and 

a number of Federal Register notices 

advised the public of the peer review 

process and all the meetings were open 

to the public for comment and 

participation and the minutes of those 

meetings were posted on the SAB Web 

site. The minutes for the June 2011 

meeting, during which EPA provided 

clarifying information, were available 

well within the public comment period 

for the proposed rule. For these reasons, 

we maintain that the public was 

provided an adequate opportunity to 

comment on the Hg risk assessment. 

e. Non-Hg HAP Case Studies 

1. Emissions for Non-Hg Case Studies 

Comment: The commenters raised 

concerns about a wide variety of aspects 

of EPA’s approach for emissions used 

for the non-Hg case studies, including 

the use of an arithmetic mean for 

computing emission factors for 

representing emissions of untested 

units, the suggestion of statistical 

outliers in the Cr test data, the claim 

that metals content of the fuel is an 

indicator of flawed test data, the 

statistical approaches used by EPA to 

create emission factors, the absence in 

EPA’s approach of an equation that 

commenters claim better represents 

emissions values, that EPA’s approach 

to estimate Cr(VI) is flawed, and the lack 

of coal rank as a delineating factor for 

emission factor calculation. The 

commenters also suggested that EPA 

should revise stack parameters used for 

the case studies based on better 

available data. 

Response: In response to the 

comments on the emission factors, the 

EPA has undertaken additional analysis 

to address all commenter concerns. The 

EPA disagrees with commenter’s 

criticisms of emission factors based on 

arithmetic means, and EPA 

demonstrates that the use of an 

arithmetic mean provides the most 

representative result. The EPA analysis 

has found that the geometric mean 

approach recommended by the 

commenter always under predicts actual 

emissions by an average of more than 

seventy percent. The EPA agrees with 

commenters’ recommendations to use 

statistical outlier tests, but has applied 

tests different from those suggested by 

the commenters. As further explained in 

the response to comments document in 

the docket, this approach did not 

eliminate the Cr test data from the Cr 


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emission factors used for some of the 

case study emissions. 

The EPA disagrees with commenters’ 

assertions that the metal content of the 

coal is a basis for invalidating the test 

results of high Cr emissions. The 

identification of sources whose 

measured emissions do not match the 

commenters’ preconceived idea of 

emissions behavior is not surprising. 

There are many possible explanations 

for these differences. For example, the 

inconsistency between the test data and 

the coal analysis could be due to any 

number of reasons including 

unrepresentative coal sampling, control 

device problems, degradation of the 

refractory, or sampling contamination. 

The idea that test data should be 

discarded because it does not match 

initial expectations is unfounded. 

The EPA disagrees with the 

commenter recommendations for using 

an equation from AP–42, developed in 

part by the commenters. Based on 

analyses of metal emissions measured at 

the site compared to statistically 

predicted estimates, the EPA concluded 

that measured emissions test data better 

predict actual emissions, and emission 

factors based on the arithmetic mean are 

a reasonable method to estimate 

emissions when test data are not 

available. The EPA analysis of the ICR 

data has found that the emissions 

equation recommended by the 

commenter is not a good predictor of 

actual EGU emissions. The EPA also 

disagrees with commenters’ concerns 

about the assumption that 12 percent of 

the Cr will be Cr(VI) for every coal-fired 

unit, which was specifically supported 

by the peer review on the approach for 

estimating cancer risks associated with 

Cr and Ni emissions. The EPA disagrees 

with the commenter’s assertion that any 

impact of scrubbers will impact the case 

study analyses. In EPA’s revised case 

study analysis, 6 facilities have risk 

greater than 1 in a million, and of these, 

four facilities have Cr as the risk driver 

(James River, Conesville, TVA Gallatin, 

and Dominion—Chesapeake Bay). For 

these facilities, none of the units 

contributing the bulk of the Cr 

emissions have scrubbers according to 

the data provided to EPA by those 

facilities, so scrubber impacts on Cr 

speciation is not relevant to EPA’s 

conclusions based on the non-Hg case 

studies. In any case, the EPA disagrees 

with the commenter’s conclusions about 

the impacts of scrubbers on Cr 

speciation and provides evidence that 

impacts of scrubbers on Cr speciation 

can have the opposite effect on Cr(VI) 

fractions, concluding that EPA’s 12 

percent assumption is somewhat 

conservative. 

The EPA also disagrees that coal rank 

must be a factor in computing Cr 

emission factors for use in the case 

studies. The EPA’s analysis has 

demonstrated that coal rank appears to 

play no role in non-Hg metals 

emissions. The EPA’s newly revised 

emissions factor development 

procedures can isolate and compare 

subgroups based on control device type 

or coal rank; the ICR data were 

subjected to these tests and no statistical 

significance was found between coal 

rank groups. 

Finally, the EPA agrees with one 

commenter’s recommendations on 

revised stack parameters for the case 

studies and has included these revisions 

in the case study modeling for the final 

rule. 

2. General Comments on Non-Hg Risk 

Case Study 

Comment: One commenter stated that 

EPA’s case study assessment reaffirms 

the need to regulate HAP emitted by 

both coal and oil-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-Hg HAP indicated 

a cancer risk greater than or equal to the 

one in a million threshold level required 

to delist a source category under CAA 

section 112. 

One commenter stated that EPA’s case 

study assessment might be flawed by 

the use of ‘‘beta’’ tests versions of the 

AERMOD meteorological preprocessors 

(AERMINUTE and AERMET). The 

commenter obtained from EPA the 

meteorological data used for EPA’s 

assessment of the Conesville facility and 

processed these data with EPA’s current 

regulatory versions of these 

preprocessors, which differ from the 

beta version. According to the 

commenter, a comparison of the hourly 

wind speed and hourly wind direction 

data produced by the beta preprocessor 

and by current EPA preprocessors 

revealed numerous and often substantial 

disparities. 

One commenter stated that EPA’s 

finding that only three coal-fired 

facilities and one oil-fired facility out of 

roughly 440 coal-fired facilities and 97 

oil-fired facilities in the U.S. indicated 

risk greater than one-in-a-million 

supports a finding that it is 

‘‘appropriate’’ to regulate those four and 

not the other 537. Another commenter 

stated that EPA found only a ‘‘few’’ 

facilities that have estimated maximum 

cancer risks in excess of one in a 

million, and that this does not justify 

regulating all non-Hg HAP for all 

sources in this category. 

One commenter stated that EPA’s 

discussion in the preamble to the 

proposed rule misleads the reader into 

believing that non-Hg HAP emissions 

from EGUs are associated with serious 

human health effects. According to the 

commenter, the EPA’s discussion of the 

effects associated with excessive 

exposure to an individual HAP would 

lead the reader to believe that those 

effects inevitably occur from EGU 

emissions because EGU emissions have 

trace amounts of non-Hg HAP. 

One commenter stated that with the 

assumptions in the Utility Study, both 

in terms of conservative scientific 

estimates and overestimated amounts of 

oil burned by these units, the EPA 

concluded that the risks from oil-fired 

units would result in only one new 

cancer case every 5 years. The 

commenter does not believe that this 

level of risk warrants regulation under 

CAA section 112(n)(1)(A). 

Several commenters stated that even 

if the additional studies EPA performed 

were accurate, they hardly demonstrate 

that it is necessary and appropriate to 

regulate coal-fired EGU HAP under CAA 

section 112 because three sites 

nationwide show risks greater than one 

in a million, with the highest at eight in 

a million. 

One commenter stated that the 

highest cancer risk estimated for coalfired 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, the EPA apparently decided 

that they were justified to regulate all 

non-Hg HAP for all sources in this 

category. 

Several commenters stated that EPA’s 

assumption implies that a person stays 

exactly at the center of a census tract for 

70 years and that a unit will operate in 

exactly the same manner for 70 years is 

unrealistic. The commenters suggest 

that Tier 3 risk assessment is warranted 


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278 54 FR 38044. 

or a lifetime exposure adjustment is 

needed. 

One commenter asserts that because 

the alleged health benefits are derived 

from total exposure, the EPA should 

explain how its numerical emission 

limit units, which would not directly 

restrict total exposure if heat inputs 

increase, redress this health concern. In 

its preamble, the EPA simply notes that 

its emission limit units are consistent 

with, and allow for simple comparison 

to, other regulations. 

One commenter questioned whether 

acid gas emissions limits for oil-fired 

units are ‘‘appropriate’’ or ‘‘necessary’’ 

because EPA’s new technical analyses 

do not indicate a health concern from 

acid gas emissions from oil-fired units. 

According to the commenter, the EPA 

identifies Ni as the main HAP of 

concern from oil-fired units, even 

though cancer-related inhalation risks 

were well below the RfCs and EPA 

states that significant uncertainty 

remains as to whether those emissions 

present a health concern. 

Response: The EPA agrees with the 

commenter that the non-Hg HAP risk 

assessment confirms the appropriate 

and necessary finding. 

The EPA disagrees that EPA’s case 

study assessment is flawed by the use of 

beta versions of AERMINUTE and 

AERMET. The EPA remodeled the case 

study facilities using the current 

versions of AERMINUTE (version 

11059), AERMET (version 11059), and 

AERMOD (version 11103). Although 

there were differences in the number of 

calm and missing winds in the current 

AERMINUTE/AERMET output 

compared to the beta version, the 

resulting risks differed by less than two 

percent, on average. For Conesville, 

which had the largest difference in 

calms between the beta and current 

versions of AERMINUTE/AERMET, the 

risks differed by three percent. For the 

final rule, the case study facilities have 

been modeled with the current available 

versions of AERMINUTE, AERMET, and 

AERMOD. 

The EPA disagrees with the 

commenter that having only a few case 

study facilities exceeding one in a 

million risk invalidates the ‘‘appropriate 

finding’’. The 16 facilities EPA selected 

as case studies for assessment may not 

represent the highest-emitting or 

highest-risk sources. Although case 

study facility selection criteria included 

high estimated cancer and non-cancer 

risks using the 2005 NEI data, high 

throughput, and minimal emission 

control, another necessary criterion was 

the availability of Information 

Collection Request (ICR) data for the 

EGUs at those facilities (or for similar 

EGUs at other facilities). Because the 

ICR data were collected for the purpose 

of developing the MACT standards, the 

ICR was targeted towards better 

performing sources for non-Hg metal 

HAP, acid gas HAP, and organic HAP, 

with a smaller set of random recipients. 

Therefore, facilities for which ICR data 

were available may not represent the 

highest-emitting sources. The EPA’s 

assessment of the case study facilities 

for the proposed rule concluded that 

three coal-fired facilities and one oilfired 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. 

The EPA disagrees with the 

commenter’s assertion that the health 

effects associated with exposures to 

non-Hg HAP from U.S. EGUs are 

mischaracterized in the preamble to the 

proposed rule. The discussion of the 

health effects of non-Hg HAP provided 

in the preamble includes general 

information on the potential health 

effects associated with a broad range of 

exposure concentrations (from low to 

high levels) of the various non-Hg HAP 

(some of which have been determined to 

be carcinogenic to humans) based on 

peer reviewed scientific information 

extracted from priority sources such as 

IRIS, Cal EPA and ATSDR health effects 

assessments. 

The EPA disagrees with the 

commenter’s characterization of the 

Utility Study. The Utility Study 

represented the highest-quality factual 

record of information available at the 

time regarding EGU emissions and risks. 

Further, the EPA’s revised risk 

assessments of 16 case studies, 

performed with more recent data and 

refined scientific methods, indicate that 

there are six U.S. EGU facilities that 

pose estimated inhalation cancer risks 

greater than 1 in a million. The EPA 

maintains that the findings of the case 

studies are one element that 

independently supports our 

determination that it remains 

appropriate and necessary to regulate 

EGUs under CAA section 112. 

The EPA does not agree with the 

commenter who suggested that EPA 

should interpret the results of the nonHg HAP risk analysis in the context of 

background cancer risk. As explained in 

the preamble to the proposed rule, the 

EPA reasonably looked to the cancer 

risk threshold established under CAA 

section 112(c)(9)(B)(1) for delisting a 

source category as an indicator of the 

level of cancer risk that was appropriate 

to regulate under CAA section 112. The 

commenters comparison of the cancer 

risk from EGUs as compared with the 

risk of contracting cancer from 

unknown sources is not the standard 

Congress established for evaluating HAP 

emission risk and the commenter has 

provided no support for its contention 

that the Agency should evaluate risk in 

that manner. The EPA maintains that 

the analysis was reasonable. 

The EPA does not agree with the 

commenter’s implication that EPA must 

make a facility-specific finding for each 

HAP for each source and then only 

regulate individual EGU facilities for the 

individual HAP that identified as 

causing an identified hazard to public 

health or the environment. That 

approach is not required under CAA 

section 112(n)(1) or anywhere under 

CAA section 112, and it would be 

virtually impossible to undertake such 

an effort. For these reasons, the EPA 

does not agree with the commenter and 

maintains that the appropriate and 

necessary finding is reasonably 

supported by the record and consistent 

with the statute for all the reasons set 

forth in the preamble to the proposed 

rule and this final action. 

The EPA disagrees that an exposure 

adjustment is needed to account for 

conditions changing over 70 years 

because it runs counter to the longstanding approach that EPA has taken to 

estimate the maximum individual risk, 

or MIR. The MIR is defined by EPA’s 

Benzene NESHAP regulation of 1989 278

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 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 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9359 

279U.S. EPA, 2011c. 

280U.S. EPA, 1991. 

281California 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. 

282Texas 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. 

283 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. 

284 International Labour Organization/United 

Nations Environment Programme, World Health 

Organization (WHO), 1991. Nickel. In 

Environmental Health Criteria No 108 Geneva. 

285European Commission, Scientific Committee 

on Health and Environmental Risks (SCHER), 2006. 

Opinion on: Reports on Nickel, Human Health part. 

SCHER, 11th plenary meeting of 04 May 2006 

http://ec.europa.eu/health/ph_risk/committees/ 

04_scher/docs/scher_o_034.pdf. 

286NTP, 2011. 

support risk-based rulemakings under 

CAA section 112 to date. 

The EPA disagrees with the 

commenter’s assertion that the 

numerical emission limits being 

promulgated in today’s final rule must 

be justified on their ability to redress the 

health concerns that were identified as 

the basis for regulating EGUs. The 

emission limits in today’s rule are 

technology-based, as prescribed under 

CAA section 112, and do not need to be 

justified based on their ability to protect 

public health. Regarding potential 

health concerns, the EPA has up to 8 

years after the promulgation of the 

technology-based emission limits for 

EGUs to determine whether the 

regulations protect public health with 

an ample margin of safety. If the 

regulations do not, the CAA directs EPA 

to promulgate additional more stringent 

standards (within the prescribed 8 

years) to achieve the appropriate level of 

public health protection. 

Furthermore, the EPA reasonably 

concluded that it was appropriate and 

necessary to regulate oil-fired EGUs in 

2000, and EPA confirmed that 

conclusion was proper with the analysis 

set forth in the preamble to the 

proposed rule. Certain commenters 

question the determination based on 

their views of 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 oilfired EGUs are greater than one in a 

million, due primarily to emissions of 

Ni compounds. Based on our analysis, 

we are unable to delist oil-fired EGUs. 

3. Ni Risk 

Comment: Several commenters stated 

that the assumptions regarding the 

speciation and carcinogenic potential of 

Ni compounds used in EPA’s inhalation 

risk assessment of the case study 

facilities are overly conservative and 

likely to overstate the risks. With 

respect to Ni speciation, the 

commenters stated that there are 

substantial uncertainties regarding the 

species of Ni being emitted and the risk 

of such emissions, and that EPA has 

made ultraconservative assumptions 

aimed at overestimating the risk. The 

commenters stated that assigning the 

same carcinogenic potency of Ni 

subsulfide to other forms of Ni is overly 

conservative and inconsistent with the 

best available evidence. 

Response: The EPA disagrees with the 

commenters’ assertion that it is 

impossible to give an accurate 

assessment of the risks to human health 

from Ni emissions from EGUs, and 

maintains that its assessment of the 

potential inhalation risks from EGU 

emissions of Ni compounds is 

scientifically valid, reasonable, and 

based on the best-available current 

scientific understanding. To that end, in 

July 2011, the EPA completed an 

external peer review (using three 

independent expert reviewers) of the 

methods used to evaluate the risks from 

Ni and Cr compounds emitted by 

EGUs.279 There were two charge 

questions relating to Ni in that review. 

First, do EPA’s judgments related to 

speciated Ni emissions adequately take 

into account available speciation data, 

including recent industry spectrometry 

studies? Second, based on the 

speciation information available and 

what is known about the health effects 

of Ni compounds, and taking into 

account the existing URE values (i.e., 

values derived by the Integrated Risk 

Information System,280 California 

Department of Health Services,281 and 

the Texas Commission on 

Environmental Quality 282), 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 healthprotective approach, based on the 

consistent views of the most 

authoritative scientific bodies (i.e., NTP 

in their 12th ROC, IARC, and other 

international agencies) that consider Ni 

compounds to be carcinogenic as a 

group. 

3. To make the same assumptions as 

in option 2, but considering alternative 

UREs derived by the CDHS or TCEQ. 

In responding to these peer review 

questions, two of the reviewers agreed 

with the views of the most authoritative 

scientific bodies, which consider Ni 

compounds carcinogenic as a group. 

These reviewers, therefore, did not 

focus on the availability of Ni speciation 

profile data. The third reviewer 

recommended that EPA review several 

manuscripts on Ni speciation profiles 

showing that sulfidic Ni compounds 

(which the reviewer considered as the 

most potent carcinogens) are present at 

low levels in emissions from EGUs. 

Nickel and Ni compounds have been 

classified as human carcinogens by 

national and international scientific 

bodies including the IARC,283 the World 

Health Organization,284 and the 

European Union’s Scientific Committee 

on Health and Environmental Risks.285

In their 12th Report of the Carcinogens, 

the NTP has classified Ni compounds as 

known to be human carcinogens based 

on sufficient evidence of carcinogenicity 

from studies in humans showing 

associations between exposure to Ni 

compounds and cancer, and supporting 

animal and mechanistic data. More 

specifically, this classification is based 

on consistent findings of increased risk 

of cancer in exposed workers, and 

supporting evidence from experimental 

animals that shows that exposure to an 

assortment of Ni compounds by 

multiple routes causes malignant 

tumors at various organ sites and in 

multiple species. The 12th Report of the 

Carcinogens states that the ‘‘combined 

results of epidemiological studies, 

mechanistic studies, and carcinogenesis 

studies in rodents support the concept 

that Ni compounds generate Ni ions in 

target cells at sites critical for 

carcinogenesis, thus allowing 

consideration and evaluation of these 

compounds as a single group’’.286

Although the precise Ni compound (or 

compounds) responsible for the 

carcinogenic effects in humans is not 

always clear, studies indicate that Ni 

sulfate and the combinations of Ni 

sulfides and oxides encountered in the 

Ni refining industries cause cancer in 

humans. There have been different 

views on whether or not Ni compounds, 

as a group, should be considered as 

carcinogenic to humans. Some authors 


srobinson on DSK4SPTVN1PROD with RULES2
9360 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

287Oller A. Respiratory carcinogenicity 

assessment of soluble nickel compounds. Environ 

Health Perspect. 2002, 110:841–844. 

288Heller 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. 

289 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. 

290 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.ossup-med.com/content/5/1/7. 

291Haber 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. 

292NTP, 1996. 293U.S. EPA, 2011c. 294 54 FR 3804. 

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).287 288 289 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 

review 290 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, the 

EPA considers all Ni compounds to be 

carcinogenic as a group and does not 

consider Ni speciation or Ni solubility 

to be strong determinants of Ni 

carcinogenicity. With regards to noncancer effects, comparative quantitative 

analysis across Ni compounds indicates 

that Ni sulfate is as toxic or more toxic 

than Ni subsulfide or Ni oxide.291 292

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, the 

EPA also considers it reasonable to use 

a value that is 50 percent of the IRIS 

URE for Ni subsulfide for providing an 

estimate of the lower end of a plausible 

range of cancer potency values for 

different mixtures of Ni compounds. 

4. Cr Risk 

Comment: One commenter stated 

there are several problems with EPA’s 

analysis related to the fact that Cr 

emissions were evaluated as being 

entirely Cr(VI). The commenter stated 

that not all of the emitted Cr will remain 

in the hexavalent form by the time it 

reaches the target population, and that 

some may be converted to the much less 

toxic (and noncarcinogenic) trivalent 

species. The commenter also stated that 

the concentration levels considered in 

the case study assessment are far below 

occupational levels. The commenter 

concluded that EPA’s cancer estimates 

should, therefore, be looked on with 

some skepticism. Another commenter 

stated that EPA’s estimate of 12 percent 

Cr(VI) from coal-fired EGUs is 

unsupported, and that EPA failed to 

recognize that Cr(VI) is highly watersoluble and is easily reduced to Cr(III) 

in the presence of SO2 in a low pH 

environment. The resulting Cr(III) 

would be expected to precipitate out in 

a FGD. The commenter stated that the 

actual amount of Cr(VI) that would be 

present in the emissions from an EGU 

with a wet scrubber is likely to be far 

lower than the 12 percent estimate made 

by EPA. 

Several commenters questioned the 

validity of the chronic inhalation study 

by EPA because of (1) the use of 

surrogate speciated Cr emissions data 

instead of actual emissions data, (2) the 

assumption that units were run 100 

percent of the time which is impossible, 

(3) dispersion modeling was used that is 

biased towards over predicting 

downwind impacts, and (4) estimated 

ambient concentrations were utilized as 

substitutes for real exposure 

concentrations for all people within a 

census block. 

Response: The EPA disagrees with the 

commenters’ assertion that all Cr was 

considered to be hexavalent. As 

discussed in ‘‘Methods to Develop 

Inhalation Cancer Risk Estimates for 

Chromium and Nickel Compounds,’’ 293

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. 

The EPA also disagrees that units 

were assumed to operate 100 percent of 

the time. The dispersion modeling 

performed for the case study facilities 

used hourly heat input as a 

temporalization factor for estimating 

hourly emissions, and in some cases 

hourly heat inputs (and emissions) were 

zero or very low. The commenter 

provided no data or information to 

support their claim that the dispersion 

modeling EPA used is biased towards 

overestimating downwind impacts. 

The EPA disagrees with the 

commenters’ assertion that ‘‘real 

exposure concentrations for all people 

within a census block’’ must be 

considered because it runs counter to 

the long-standing approach that EPA 

has taken to estimate the maximum 

individual risk, or MIR. The MIR is 

defined by EPA’s Benzene NESHAP 

regulation of 1989 294 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 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 oil-fired 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 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9361 

295Appendix W to 40 CFR Part 51. 

296U.S. EPA–SAB, 2010. 

297Evans, 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. 

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: We do not agree with 

commenter’s implication that Congress 

intended EPA to regulate only those 

HAP emissions from U.S. EGUs for 

which an appropriate and necessary 

finding is made, and commenter has 

cited no provision of the statute that 

states a contrary position. The EPA 

concluded that we must find it 

‘‘appropriate’’ to regulate EGUs under 

CAA section 112 if we determine that a 

single HAP emitted from EGUs poses a 

hazard to public health or the 

environment. If we also find that 

regulation is necessary, the Agency is 

authorized to list EGUs pursuant to 

CAA section 112(c) because listing is 

the logical first step in regulating source 

categories that satisfy the statutory 

criteria for listing under the statutory 

framework of CAA section 112. See New 

Jersey, 517 F.3d at 582 (stating that 

‘‘[s]ection 112(n)(1) governs how the 

Administrator decides whether to list 

EGUs * * *’’). As we noted in the 

preamble to the proposed rule, D.C. 

Circuit precedent requires the Agency to 

regulate all HAP from major sources of 

HAP emissions once a source category 

is added to the list of categories under 

CAA section 112(c). National Lime 

Ass’n v. EPA, 233 F.3d 625, 633 (D.C. 

Cir. 2000). 76 FR 24989. The EPA 

discusses in the preamble to the 

proposed rule and this final action its 

concerns with HCl and other acid gas 

HAP emissions from EGUs and the 

Agency’s approach for establishing 

section 112(d) standards for acid gas 

HAP. 

6. EPRI Risk Analysis 

Comment: Two commenters stated 

that a comprehensive tiered inhalation 

risk assessment (the EPRI study) using 

EPA-prescribed methods with improved 

emission factors, fuel data, and 

confirmed stack parameters did not 

identify significant health risks (cancer 

or non-cancer) among U.S. coal-fired 

power plants (as they existed in 2007). 

The commenters noted that these results 

contrast with those presented by EPA 

for its non-Hg case studies on 16 (15 

coal-fired) power plants. The 

commenters stated that several issues 

appear to underlie these differences, 

indicating the need for EPA to 

reevaluate its assessment and to 

undertake more refined (Tier 3) risk 

assessment for any facility of concern. 

Several commenters stated that for nonHg HAP EPA produced one study on 

chronic inhalation risk assessment that 

identified three sites with cancer risks 

greater that one in a million for Cr(VI), 

which was authored by EPA staff and 

not peer reviewed. One commenter 

stated that EPA study is based on 

misinformation and overestimates 

assumptions, and that EPA has no data 

demonstrating health impacts from EGU 

emissions of non-Hg HAP, or the benefit 

from reducing such emissions. Two 

commenters stated that no benefits will 

be derived from the non-Hg HAP 

emission reductions associated with the 

proposed rule because no non-Hg HAP 

health risks were proven, and that no 

showing was made that EGU non-Hg 

HAP emission levels reach levels 

associated with adverse health effects. 

Another commenter stated that EPA 

must complete a comparable and 

separate national-scale risk assessment 

for non-Hg metals in order to determine 

appropriateness of proposing emissions 

standards for non-Hg metals. 

Response: The commenters are 

incorrect in the assertion that EPA’s 

case studies were performed with less 

rigor than the EPRI analysis. The EPRI 

analysis used a tiered approach to risk 

assessment, beginning with Tier 1 using 

EPA’s SCREEN3 dispersion model on all 

470 coal-fired power plants in the U.S., 

and following with Tier 2 with EPA’s 

Human Exposure Model (which uses the 

AERMOD dispersion model) for plants 

with higher risks from the Tier 1 

modeling. Although tiered risk 

assessment is an appropriate approach, 

the Tier 2 modeling could have been 

more refined. For example, more 

meteorological data could have been 

used and building downwash could 

have been considered. The EPRI 

analysis ostensibly concluded that the 

Tier 2 modeling with HEM was 

conservative, and that because the 

modeled risks did not exceed certain 

thresholds, no further refinement was 

necessary. 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.295

In contrast to the approach used in 

the EPRI analysis, the EPA used: 

(1) 5 years of recent meteorological data 

from the weather station nearest to each 

facility, rather than one year of 

meteorological data. This is more 

representative of 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]. 

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 2009.296 The SAB 

issued its peer review report in May 

2010. The report generally endorsed the 

risk assessment methodologies used in 

the program. In addition, in July 2011, 

the EPA completed a letter peer review 

of the methods used to develop 

inhalation cancer risk estimates for Cr 

and Ni compounds. 

f. Ecosystem Impacts From HAP 

Comment: Two commenters assert 

that EPA is not justified in regulating 

acid gases based on concern about the 

potential that acid gases contribute to 

ecosystem acidification rather than 

concerns about hazards to public health. 

The commenters further claim that 

HCl’s contribution to ecosystem 

acidification is de minimis. The 

commenters point out that EPA 

acknowledges uncertainty in 

quantification of acidification and EPA 

relies on recently published research 297

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 


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9362 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

298 Id. 

299U.S. Environmental Protection Agency (U.S. 

EPA). 2009. Risk and Exposure Assessment for 

Review of the Secondary National Ambient Air 

Quality Standards for Oxides of Nitrogen and 

Oxides of Sulfur (Final). EPA–452/R–09–008a. 

Office of Air Quality Planning and Standards, 

Research Triangle Park, NC. September. Available 

on the Internet at http://www.epa.gov/ttn/naaqs/

standards/no2so2sec/data/NOxSOxREASep2009

MainContent.pdf. 

300U.S. Environmental Protection Agency (U.S. 

EPA). 2011d. Policy Assessment for the Review of 

the Secondary National Ambient Air Quality 

Standards for Oxides of Nitrogen and Oxides of 

Sulfur. EPA–452/R–11–005a. Office of Air Quality 

Planning and Standards, Research Triangle Park, 

NC. February. Available on the Internet at http://

www.epa.gov/ttnnaaqs/standards/no2so2sec/data/

20110204pamain.pdf. 

301U.S. EPA, 2009. 

302Ecotoxicology 17:83–91, 2008. 303This corresponds to 28 percent of modeled 

watersheds with populations potentially at-risk in 

the analysis reported in the preamble to the 

proposed rule. 

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.,298 acid gases can significantly 

contribute to acidification. The EPA 

published a comprehensive risk 

assessment of acidification effects of 

nitrogen and sulfur deposition 299 and a 

policy assessment.300 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 

evidence that show (1) that HCl is 

highly mobile in the environment, 

transferring acidity easily through soils 

and water, (2) that HCl can transport 

longer distances than previously 

thought (given its presence in remote 

ecosystems, and (3) that it can be a 

larger driver of acidification than 

previously thought. The fact that this 

study took place in the U.K. is itself 

irrelevant. The chemical interactions of 

HCl in water are the same the world 

over and sensitive ecosystems exist in 

the U.S. as well as in Europe as 

illustrated in the ecological risk 

assessment 301 for NOX and SOX. 

Furthermore, the commenter is factually 

incorrect that EPA is justifying that it is 

appropriate and necessary to regulate 

HAP emissions from EGUs based on this 

one study. The EPA agrees with the 

commenter that Hg exposure in wildlife 

is responsible for various adverse health 

effects in many species across the U.S. 

and recognizes that research is ongoing 

in this area. As discussed in the 

preamble to the proposed rule, the EPA 

agrees that there are potential 

environmental risks from exposures of 

ecosystems through Hg and non-Hg 

HAP deposition. The EPA cited relevant 

articles from the special edition of 

Ecotoxicology 302 mentioned by the 

commenter in the ecosystem effects 

section on Chapter 5 of the RIA for this 

rule, which is available in the docket. 

G. EPA Affirms the Finding That It Is 

Appropriate and Necessary to Regulate 

EGUs To Address Public Health and 

Environmental Hazards Associated 

With Emissions of Hg and Non-Hg HAP 

From EGUs 

In response to peer reviews of both 

the Hg and non-Hg HAP risk analyses, 

and taking into account public 

comments, the EPA conducted revised 

analyses of the risks associated with 

emissions of Hg and non-Hg HAP from 

U.S. EGUs. These revised analyses 

demonstrated that the risk results 

reported in the preamble to the 

proposed rule are robust to revisions in 

response to the peer reviews and public 

comments. 

Specifically, the revised Hg Risk TSD 

shows that up to 29 percent of modeled 

watersheds have populations potentially 

at-risk from exposure to Hg from U.S. 

EGUs.303 This 29 percent of watersheds 

with populations potentially at-risk 

includes up to 10 percent of modeled 

watersheds where deposition from U.S. 

EGUs alone leads to potential exposures 

that exceed the MeHg RfD, and up to 24 

percent of modeled watersheds where 

total potential exposures to MeHg 

exceed the RfD and U.S. EGUs 

contribute at least 5 percent to Hg 

deposition. Each of these results 

independently supports our conclusion 

that U.S. EGUs pose hazards to public 

health. 

In the preamble to the proposed rule 

and in the 2000 finding, the EPA 

explained at length the serious nature of 

the health effects associated with Hg 

exposures, and the persistent nature of 

Hg in the environment. Congress 

specifically recognized the significant 

impacts of persistent bioaccumulative 

pollutants, like Hg, when it enacted 

section 112(c)(6), which requires the 

EPA to subject source categories listed 

pursuant to that section to MACT 

standards. Congress also required 

certain studies be conducted under CAA 

section 112(n) regarding the health 

effects of Hg. The EPA interprets CAA 

section 112(n)(1), with regard to Hg, as 

intended to protect the public, 

including sensitive populations, against 

exposures to Hg from EGUs that would 

exceed the level determined by the EPA 

to be without appreciable risk, e.g., 

exposures that are above the RfD for 

methylmercury (MeHg), or would 

contribute additional risk in areas where 

Hg exposures exceed the RfD due to 

contributions from all sources of Hg. 

Our recent technical analyses show that 

98 percent of the watersheds for which 

we had fish tissue data have total Hg 

deposition such that potential exposures 

exceed the MeHg RfD, above which 

there is an increased risk of adverse 

effects on human health. In these 

watersheds, any reductions in exposures 

to Hg will reduce risk, and thus the 

incremental contribution to Hg exposure 

from any individual source or group of 

sources, such as EGUs, may reasonably 

be anticipated to cause additional risk. 

As we have explained, in calculating 

the estimates described above, the EPA 

has used peer-reviewed methods, and 

focused on populations likely to be at 

higher risk of exposure to Hg from U.S. 

EGUs, e.g., female subsistence fishing 

populations consuming at the 99th 

percentile fish consumption rate. The 

EPA did not, however, use the most 

conservative assumptions that would 

lead to upper bound risk estimates. As 

discussed above and in the revised Hg 

Risk TSD, we did not use the highest 

fish tissue cooking loss adjustment 

factor that was reported in the literature, 

which, had we done so, would have 

increased the estimates of Hg exposure 

substantially. Thus, we believe our 

analysis could understate risk to the 

most exposed individual, noting that we 

have focused on the 99th percentile 

consumption rate in our estimates. 

Further, we were able to assess 

potential Hg exposures in only a small 

subset of generally representative 

watersheds in the U.S. because our 

analysis was necessarily premised on 

those water bodies for which we had 

fish tissue Hg samples. Specifically, we 

analyzed 3,141 of the approximately 

88,000 watersheds in the United States. 

This limited set of watersheds excludes 

several of the watersheds with the 

highest U.S. EGU attributable 

deposition, and may also not have 

included watersheds with the highest 

sensitivity to Hg deposition, e.g., the 

highest methylation rates (see above). 

Nevertheless, our analysis of the subset 

of watersheds we examined 

demonstrates that almost one third of 

the watersheds are estimated to have Hg 

deposition attributable to U.S. EGUs 

that contributes to potential exposures 

above the MeHg RfD. The SAB 


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confirmed that the subset of watersheds 

we examined is sufficient. 

Considering these points and the 

information on Hg in the record, the 

EPA believes that 10 percent of 

watersheds with populations at risk due 

to U.S. EGU emissions alone is 

unacceptable, as is 24 percent of 

watersheds with populations at risk due 

to U.S. EGU contributions in 

conjunction with total deposition from 

other sources. Taking into account the 

percentage of watersheds at risk, and the 

potential for even higher percentages to 

be at risk using more conservative risk 

assumptions and a more complete 

coverage of high U.S. EGU Hg 

deposition watersheds, the EPA 

concludes that Hg emissions from U.S. 

EGUs pose a hazard to public health. 

Given these findings, and considering 

that (1) the revised risk analysis showed 

the percent of modeled watersheds with 

populations potentially at-risk increased 

from 28 to 29 percent, and (2) the 

revised analysis includes 36 percent 

more watersheds, which significantly 

expands the coverage in several states, 

we conclude that the finding that 

emissions of Hg from U.S. EGUs pose a 

hazard to public health is confirmed by 

the national-scale revised Hg Risk TSD. 

As a result, we conclude that it remains 

appropriate to regulate Hg emissions 

from U.S. EGUs because those Hg 

emissions pose a hazard to public 

health. 

With regards to the revised non-Hg 

inhalation case studies, the highest 

estimated individual lifetime cancer risk 

for the one case study facility (out of 16) 

with oil-fired EGUs is estimated to be 20 

in a million, driven by Ni emissions. For 

the facilities with coal-fired EGUs, there 

were five (out of 16) with maximum 

individual cancer risks greater than one 

in a million (the highest was five in a 

million), four of which were driven by 

emissions of Cr(VI), and one of which 

was driven by emissions of Ni. 

Therefore, a total of six facilities exceed 

the criterion for EGUs to be regulated 

under CAA section 112. There were also 

two facilities with coal-fired EGUs with 

maximum individual cancer risks at one 

in a million. In the preamble to the 

proposed rule, we reported that the 

maximum individual lifetime cancer 

risk for the one facility with oil-fired 

EGUs was estimated to be 10 in a 

million, and that there were 3 coal-fired 

EGU facilities with maximum 

individual cancer risks greater than 1 in 

a million (the highest was 8 in a 

million), and 1 coal-fired EGU facility 

with maximum individual cancer risks 

equal to 1 in a million. Given that (1) 

the lifetime cancer risk for the oil-fired 

EGU facility has increased from 10 to 20 

in a million, (2) the number of coal-fired 

EGU facilities with cancer risks greater 

than 1 in a million has increased from 

3 to 5, and (3) the highest risk coal-fired 

facility still has cancer risks of 5 in a 

million, which is above the 1 in a 

million benchmark, we conclude that 

the finding that emissions of non-Hg 

HAP from U.S. EGUs pose a hazard to 

public health is confirmed by the 

revised non-Hg risk inhalation case 

studies. 

Moreover, some HAP emissions from 

U.S. EGUs contribute to adverse 

ecosystem effects. While we did not do 

new analyses on these topics, we 

reiterate that (1) Hg emissions from U.S. 

EGUs pose a hazard to the environment, 

contributing to adverse impacts on fisheating 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 (4) it is 

appropriate to regulate those HAP 

which are not known to cause cancer 

but are known to contribute to chronic 

non-cancer toxicity and environmental 

degradation, such as the acid gases. In 

addition, we have identified effective 

controls available to reduce Hg and nonHg HAP emissions. 

In summary, we confirm the findings 

that Hg and non-Hg HAP emissions 

from U.S. EGUs each pose hazards to 

public health and that it remains 

appropriate to regulate U.S. EGUs under 

CAA section 112 for those reasons. We 

also conclude that it remains 

appropriate to regulate EGUs under 

CAA section 112 because of the 

magnitude of Hg and non-Hg emissions 

and the environmental effects of Hg and 

some non-Hg emissions, each of which 

standing alone, supports the appropriate 

finding. The availability of controls to 

reduce HAP emissions from EGUs only 

further supports the appropriate finding. 

Our revised analyses still show that in 

2016 after implementation of other 

provisions of the CAA, HAP emissions 

from U.S. EGUs are reasonably 

anticipated to pose hazards to public 

health; therefore, it is necessary to 

regulate EGUs under CAA section 112. 

Moreover, HAP emissions from U.S. 

EGUs are expected to continue to 

contribute to adverse ecosystem effects. 

In addition, based on evaluation of the 

regulations required by the CAA, 

including the recent CSAPR, it is 

necessary to regulate U.S. EGUs under 

CAA section 112 because the only way 

to ensure permanent reductions in HAP 

emissions from U.S. EGUs and the 

associated risks to public health and the 

environment is through standards set 

under CAA section 112. While CSAPR 

is projected to achieve some Hg 

reductions due to co-control of Hg 

provided by controls put in place to 

achieve required reductions in SO2

emissions, the results of the revised Hg 

Risk TSD indicate that an unacceptable 

percentage of modeled watersheds have 

populations potentially at-risk from U.S. 

EGU-attributable Hg deposition would 

remain after implementation of CSAPR. 

While we modeled slightly higher Hg 

emissions from U.S. EGUs (i.e., 29 tons 

of Hg) in our risk analysis compared to 

the most recent estimate of 27 tons, we 

do not believe this 2 ton difference 

would substantially change our finding 

that Hg emissions from U.S. EGUs pose 

a hazard to public health or the Hg risks 

reported in the preamble to the 

proposed rule, as this represents less 

than a 10 percent reduction in Hg 

emissions. In addition, the actual 

reductions in Hg that will occur due to 

application of controls to meet the SO2

emissions requirements of CSAPR may 

differ from those projected to occur, due 

to differences in the technologies that 

individual EGU sources choose to 

install. The only way to ensure 

reductions in Hg, including those 

modeled as resulting from the CSAPR, 

is to directly regulate Hg emissions 

under CAA section 112. 

In summary, we confirm the findings 

that it is necessary to regulate HAP 

emissions from U.S. EGUs because 

(1) the national-scale Hg Risk TSD 

shows that the hazards to public health 

posed by Hg emissions from U.S. EGUs 

will not be addressed through 

imposition of the CAA, (2) we cannot be 

certain that the identified cancer risks 

attributable to U.S. EGUs will be 

addressed through imposition of the 

requirements of the CAA, (3) the 

environmental hazards posed by 

acidification will not be fully addressed 

through imposition of the CAA, (4) 

regulation under CAA section 112 is the 

only way to ensure that all HAP 

emissions reductions that have been 

achieved since 2005 remain permanent, 

and (5) direct control of Hg emissions 

affecting U.S. deposition is only 

possible through regulation of U.S. 

emissions as we are unable to control 

global emissions directly. All of these 

findings independently support a 

finding that it is necessary to regulate 

U.S. EGUs under CAA section 112. 

Based on these findings, the Agency 

affirms its finding that it remains 

appropriate and necessary to regulate 


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9364 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

coal- and oil-fired EGUs under CAA 

section 112, and maintains that the 

inclusion of coal- and oil-fired EGUs on 

the CAA section 112(c) list of source 

categories regulated under CAA section 

112 remains valid. 

IV. Denial of Delisting Petition 

During the comment period on the 

proposed rule, UARG submitted a 

petition pursuant to CAA section 

112(c)(9), asking the Agency to delete a 

portion of the EGU source category from 

the list of source categories to be 

regulated under CAA section 112. 

Specifically, UARG asks that EPA delist 

coal-fired EGUs from the CAA section 

112(c) source category list. A copy of 

UARG’s petition has been placed in the 

docket for today’s rulemaking, along 

with the analysis conducted by EPRI 

that UARG uses to support its petition 

(hereinafter referred to as UARG’s 

analysis). In support of its petition, 

UARG asserts that: (1) No coal-fired 

EGU or group of coal-fired EGUs will 

emit HAP in amounts that will cause a 

lifetime cancer risk greater than one in 

one million; and (2) no coal-fired EGU 

or group of coal-fired EGUs will emit 

non-carcinogenic HAP in amounts that 

will exceed a level which is adequate to 

protect public health with an ample 

margin of safety or cause adverse 

environmental effects. We disagree with 

UARG’s assertions and for the reasons 

set forth below are denying UARG’s 

petition to delist coal-fired EGUs from 

the section 112(c) source category list. 

A. Requirements of CAA Section 

112(c)(9) 

CAA section 112(c)(9)(B) provides 

that ‘‘[t]he Administrator may delete 

any source category’’ from the section 

112(c) source category list if the Agency 

determines that: (i) For HAP that may 

cause cancer in humans, ‘‘no source in 

the category (or group of sources in the 

case of area sources) emits such 

hazardous air pollutants in quantities 

which may cause a lifetime risk of 

cancer greater than one in one million 

to the individual in the population who 

is most exposed to emissions of such 

pollutants from the source (or group of 

sources in the case of area sources)’’; 

and (ii) for HAP that may result in 

human health effects other than cancer 

or adverse environmental effects, ‘‘a 

determination that emissions from no 

source in the category or subcategory 

concerned (or group of sources in the 

case of area sources) exceed a level 

which is adequate to protect public 

health with an ample margin of safety 

and no adverse environmental effect 

will result from emissions from any 

source.’’ 

The EPA has the discretion to delete 

a source category under CAA section 

112(c)(9)(B), but only if EPA concludes 

that the relevant requirements of CAA 

section 112(c)(9)(B) have been met. HAP 

emissions from EGUs present both 

cancer risks, which implicate the 

requirements of CAA section 

112(c)(9)(B)(i), and non-cancer human 

health effects or adverse environmental 

effects, which implicate the 

requirements of CAA section 

112(c)(9)(B)(ii). As such, UARG bears 

the burden of demonstrating that the 

requirements of both clauses are met. 

B. Rationale for Denying UARG’s 

Delisting Petition 

The EPA is denying UARG’s petition 

to delist EGUs from the CAA section 

112(c) source category list. UARG 

improperly seeks to delist a portion of 

a CAA section 112(c) listed source 

category that emits carcinogens, which 

is contrary to the plain language of CAA 

section 112(c)(9). Even setting aside this 

fundamental defect, UARG has failed to 

meet the requirements of CAA section 

112(c)(9)(B). 

1. UARG’s Attempt to Delist a Portion 

of a Listed Source Category Conflicts 

With D.C. Circuit Precedent 

In December 2000, the EPA listed 

coal- and oil-fired EGUs as a single 

source category. UARG asks the Agency 

to delist a portion of that listed source 

category: Coal-fired EGUs. UARG’s 

request conflicts, however, with D.C. 

Circuit precedent, which provides that 

for categories, like EGUs, that pose 

cancer risks, the EPA may not delist a 

portion of a source category. NRDC v. 

U.S. EPA, 489 F.3d 1364 (D.C. Cir. 

2007). Specifically, in NRDC, the D.C. 

Circuit held that the Agency’s attempt to 

delist a ‘‘low-risk’’ subcategory was 

‘‘contrary to the plain language of the 

statute,’’ and that the statute only 

authorized the agency to remove source 

categories pursuant to section 112(c)(9). 

Id. at 1373 (‘‘Because EPA’s 

interpretation of Section 112(c)(9) as 

allowing it to exempt the risk-based 

subcategory is contrary to the plain 

language of the statute, the EPA’s 

interpretation fails at Chevron step 

one.’’). 

UARG’s request is indistinguishable 

from the situation before the court in 

NRDC. UARG does not seek to delist 

coal- and oil-fired EGUs, which is the 

source category that EPA listed, but 

rather a portion of that category. UARG 

also does not dispute that coal-fired 

EGUs emit carcinogenic HAP. Because 

UARG’s request to delist is contrary to 

the plain language of CAA section 

112(c)(9)(B) and NRDC, we are denying 

the delisting petition. 

2. Even Assuming, for the Sake of 

Argument, That EPA Could Delist a 

Portion of a Source Category, UARG has 

Failed to Meet the Requirements of CAA 

Section 112(c)(9) 

Even assuming, for the sake of 

argument, that EPA could delist a 

portion of a source category that emits 

carcinogens, which it cannot, UARG has 

failed to demonstrate that the 

requirements for delisting in CAA 

section 112(c)(9)(i) and (ii) have been 

met. UARG contends that it used EPA’s 

models and approaches, as well as the 

most recent data. We have carefully 

reviewed UARG’s analyses, however, 

and found certain flaws that we believe 

bias their risk results low. Specifically, 

we identified flaws in emissions 

estimation. UARG developed estimates 

for all EGU facilities using data which 

pre-date the 2010 ICR emissions 

measurement data that EPA obtained to 

support this rule. UARG also relied 

upon an emissions equation developed 

by EPRI and DOE to develop its metal 

emissions estimates. With regard to that 

approach, the EPA analysis of the ICR 

data has found that the regression 

approach is not a good predictor of 

actual EGU emissions. Furthermore, we 

found fault with their use of the 

geometric mean and their outlier 

analysis for computing emission factors. 

The EPA analysis has found that the 

geometric mean approach underpredicts 

actual emissions by an average of more 

than seventy percent. This had an 

especially large impact on the arsenic, 

chromium, and nickel emissions 

estimates. These and other issues are 

explained in further detail in the 

response to comments document. As a 

result, we believe the resulting risk 

estimates in UARG’s analysis are biased 

low. In addition, we note that there are 

dispersion model refinements that are 

not included in the UARG analyses, but 

were included in EPA’s analysis. For 

example, for the dispersion modeling of 

the 16 non-Hg case studies, the EPA 

considered building downwash and 

used time-varying emissions, neither of 

which were used in UARG’s analysis. 

These factors could also bias the UARG 

risk estimates low. 

However, even taking UARG’s 

analysis at face value and accepting, for 

arguments’ sake, their assumptions and 

emissions estimates, UARG’s own data 

supports denial of the petition because 

UARG itself identifies a maximum 

individual cancer risk exceeding 1 in a 

million, which is the statutory threshold 

in CAA section 112(c)(9)(B)(i). 

Specifically, UARG’s multi-pathway 


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model plant ingestion risk analysis 

concluded that adult anglers would face 

cancer risks of 4 in a million. For this 

reason alone, the petition should be 

denied. 

UARG dismisses the 4 in a million 

cancer result, arguing that the refined 

model plant multipathway risk 

assessment that it conducted is ‘‘overly 

conservative.’’ UARG conducted its 

multi-pathway risk analysis to evaluate 

the risks associated with ingesting 

persistent and bioaccumulative HAP 

which are emitted into the atmosphere 

and subsequently deposit into the 

environment and bioaccumulate in 

animals which are eventually consumed 

as food. Instead of conducting this 

multipathway analysis for each EGU 

facility, UARG instead analyzed multipathway risks by evaluating a single 

model plant. Nothing in the record 

indicates, however, that UARG’s model 

plant represents the worst-case scenario 

for cancer human health risks from any 

EGU. Indeed, although UARG claims in 

its petition that the site selected for its 

case study is ‘‘likely as close to a worstcase scenario as is possible given the 

numerous variables associated with 

ingestion pathway risks’’ (UARG 

petition at 12), the supporting 

documentation for that case study 

specifically acknowledges that its 

fictional model plant scenario ‘‘is not 

intended to represent the risk due to 

emissions from an actual plant or the 

highest level of risk that could be 

associated with a coal-fired power plant 

at any location’’ (EPRI at 1). The statute 

requires that no source in the category 

may cause a lifetime cancer risk greater 

than one in one million to the most 

exposed individual, and UARG has 

failed to make this showing. UARG has 

neither modeled multi-pathway risks for 

a worst-case model facility, nor 

evaluated the multipathway risks 

associated with each individual EGU 

facility. Accordingly, UARG has not 

made the demonstration required by 

CAA section 112(c)(9)(B)(i). But, even 

focusing on the multi-pathway risk 

analysis that UARG did conduct, which 

admittedly does not represent a worstcase facility, UARG’s analysis still 

shows cancer risks greater than one in 

a million. Accordingly, UARG’s petition 

must be denied. 

Although it is not necessary to reach 

the requirements of CAA section 

112(c)(9)(B)(ii) that address non-cancer 

human health risks, we note that UARG 

has also failed to show that ‘‘emissions 

from no source in the category * * * 

exceed a level which is adequate to 

protect public health with an ample 

margin of safety.’’ Again, even 

accepting, for argument’s sake, the 

conclusions in UARG’s analysis, UARG 

only evaluated the non-cancer 

inhalation risks associated with each 

EGU facility. It did not conduct a 

similar analysis to assess multipathway 

risks for each EGU facility. Instead, it 

conducted a model plant analysis and 

admits that such model plant does not 

represent the worst-case scenario for 

noncancer human health risks from any 

EGU. Thus, the analysis fails to fully 

characterize noncancer multipathway 

risks for the source category, and 

UARG’s petition must be denied on this 

basis as well. 

Finally, UARG failed to meet its 

burden of showing that ‘‘no adverse 

environmental effect will result from 

emissions from any source’’ pursuant to 

CAA section 112(c)(9)(B)(ii). UARG 

analyzed environmental effects only in 

conjunction with its model plant. 

Because UARG’s model plant does not 

represent the worst-case scenario for 

environmental effects, UARG’s analysis 

falls short and fails to characterize fully 

the potential environmental impacts, 

and UARG’s petition must be denied. 

For all of these reasons, the EPA 

denies UARG’s petition to delist coalfired EGUs from the CAA section 112(c) 

source category list. 

C. EPA’s Technical Analyses for the 

Appropriate and Necessary Finding 

Provide Further Support for the 

Conclusion That Coal-Fired EGUs 

Should Remain a Listed Source 

Category 

The EPA reasonably concluded in 

December 2000, based on the 

information available to the Agency at 

that time, that it was appropriate and 

necessary to regulate coal- and oil-fired 

EGUs under CAA section 112 and added 

such units to the list of source categories 

subject to regulation under CAA section 

112(d). As discussed in section III 

above, the EPA conducted additional, 

extensive technical analyses based on 

recent data that confirm it remains 

appropriate and necessary to regulate 

HAP from coal- and oil-fired EGUs, 

because such EGUs continue to pose 

hazards to public health. HAP emissions 

from coal- and oil-fired EGUs also 

continue to cause adverse 

environmental effects. UARG advances 

several arguments, challenging the 

analyses the Agency completed in 

support of the proposed rule. We 

address those arguments in section III 

above. The Agency’s analyses 

supporting the appropriate and 

necessary finding confirm that EGUs 

cannot be delisted pursuant to CAA 

section 112(c)(9). 

Specifically, as explained further in 

section III above, the EPA analyzed nonHg inhalation risks from 16 EGU facility 

case studies, including both coal- and 

oil-fired EGUs, as part of its technical 

analyses supporting the appropriate and 

necessary finding. That analysis 

demonstrates that there are 6 EGU 

facilities (of the 16 that we analyzed) 

with cancer risks exceeding one in one 

million. These cancer risk levels exceed 

the delisting criteria set forth in CAA 

section 112(c)(9)(B)(i), and confirm that 

EGUs must remain a listed source 

category. As explained above, some 

commenters assert that EPA’s analysis 

of non-Hg inhalation risks from EGUs 

conducted in support of the proposal for 

this rulemaking overstated emissions 

from, and risks associated with, EGUs. 

These commenters argue that the 

analysis supporting UARG’s petition 

more appropriately assesses EGU risk. 

The EPA disagrees with these comments 

and addresses these comments in 

section III above. 

Significantly, the EPA based its 

analysis of 16 case study EGUs directly 

on the 2010 emissions test data from 

EGUs obtained through the ICR. The 

EPA’s 16 case study analysis used 

emissions data either taken directly 

from the 2010 emissions test data, or 

derived using emissions factors based 

on the 2010 data for similar EGU units. 

The EPA also included dispersion 

model refinements in its final case 

studies, as noted above. Further, the 

EPA re-analyzed the 16 case studies that 

we conducted for the proposal and 

revised those analyses consistent with 

new non-Hg HAP emissions data and 

corrected stack parameters provided by 

commenters (including UARG) during 

the comment period on the proposed 

rule. The EPA received revised 

information concerning emissions tests, 

stack heights and stack diameters for 

some of the case study EGU facilities. 

The EPA incorporated all of these 

corrections into our analysis and then 

re-analyzed the risks for the 16 case 

study facilities. When completed, the 

EPA determined that the corrections 

incorporated into the reanalysis had 

little effect on the overall results. In the 

final rule, the EPA concludes that the 

maximum individual inhalation cancer 

risks for 6 out of the 16 case study EGU 

facilities are greater than 1 in a million. 

These cancer risk levels confirm that 

EGUs do not satisfy the delisting 

criterion of CAA section 112(c)(9)(B)(i) 

and thus should remain a listed source 

category. 

The EPA’s national-scale Hg Risk TSD 

supporting the appropriate and 

necessary finding also confirm that Hg 

emissions from coal- and oil-fired US 

EGUs are reasonably anticipated to pose 

a hazard to public health. As discussed 


srobinson on DSK4SPTVN1PROD with RULES2
9366 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

304The same is true with respect to section 

112(c)(9)(B)(i). 

305 In a prior rulemaking, EPA stated that the 

language in section 112(c)(9)(B)(ii) ‘‘does not direct 

EPA to extend its analysis to either emissions from 

other sources in other categories or subcategories or 

to non-attributable background concentrations.’’ 71 

FR 8347 (Feb. 16, 2006). The preamble to that rule 

repeatedly states that the ‘‘focus’’ of the delisting 

determination in that rule was on emissions from 

sources in the category under review. See 71 FR 

8346–47. The preamble went on to compare section 

112(c)(9)(B) to section 112(f)(2)(A) in a way that 

suggested that EPA can consider risks presented by 

sources other than the subject source category 

under section 112(f)(2), but not under section 

112(c)(9). We do not believe the language of section 

112(c)(9) compels any different treatment. The 

section 112(f) analysis occurs after a source category 

has already complied with section 112(d) standards, 

whereas, potential delistings under section 

112(c)(9) may involve source categories unregulated 

by section 112. A delisting decision is significant 

in that the category that is delisted will no longer 

be subject to HAP regulation under the Act. It is 

difficult to justify why we would examine risks 

from other sources under section 112(f), but not 

under section 112(c)(9), where Congress established 

such a specific test for delisting. 

in section III above, the EPA interprets 

CAA section 112(n)(1), with regard to 

mercury, as intended to protect the 

public, including sensitive populations, 

against exposures to Hg from EGUs that 

would exceed the level determined by 

EPA to be without appreciable risk, e.g., 

exposures that are above the RfD for 

methylmercury (MeHg), or would 

contribute additional risk in areas where 

Hg exposures exceed the RfD due to 

contributions from all sources of Hg. 

In order to determine whether EGU 

Hg emissions pose a hazard to public 

health, the EPA conducted a nationalscale Hg Risk TSD focused on 

populations with high levels of selfcaught freshwater fish consumption. 

The results of the Hg Risk TSD show 

that 98 percent of modeled watersheds 

have total exposures to MeHg that 

exceed the MeHg RfD, above which 

there is an increased risk of adverse 

effects on human health. In these 

watersheds, any reductions in exposures 

to Hg will reduce risk, and thus the 

incremental contribution to Hg exposure 

from any individual source or group of 

sources, such as EGUs, may reasonably 

be anticipated to cause additional risk. 

The Hg Risk TSD focused on those 

watersheds that either exceeded the RfD 

based on U.S. EGU attributable 

deposition alone, without considering 

other sources of deposition, or 

watersheds that exceed the RfD due to 

total Hg deposition and to which U.S. 

EGUs contributed at least 5 percent of 

the Hg deposition. The results of that 

analysis show that up to 29 percent of 

the modeled watersheds have 

populations that are potentially at-risk 

from exposure to Hg from U.S. EGUs, 

including up to 10 percent of modeled 

watersheds where deposition from U.S. 

EGUs alone leads to potential exposures 

that exceed the MeHg RfD, and up to 24 

percent of modeled watersheds where 

total potential exposures to MeHg 

exceed the RfD and U.S. EGUs 

contribute at least 5 percent to Hg 

deposition. This approach to assessing 

national risks from Hg deposition from 

EGUs was supported by the 

independent peer review conducted by 

the Science Advisory Board, as 

discussed fully in section III. 

Finally, as discussed in section III, 

based on this assessment, the EPA has 

confirmed that Hg emitted from U.S. 

EGUs pose a hazard to public health and 

it is appropriate to regulate U.S. EGUs 

under CAA section 112. This 

determination and the confirmatory 

assessments support our conclusion that 

UARG’s delisting petition must be 

denied. 

UARG attempts to dismiss the results 

of EPA’s national-scale Hg Risk TSD, 

arguing that EPA cannot consider the 

risks posed by EGUs in conjunction 

with any other risks, including those 

from other source categories. Nothing in 

CAA section 112(c)(9), however, 

provides that the Agency cannot 

consider background or emissions due 

to other sources. CAA section 

112(c)(9)(B)(ii) provides that ‘‘no source 

in the category or subcategory 

concerned (or group of sources in the 

case of area sources) exceed a level 

which is adequate to protect public 

health with an ample margin of safety 

and no adverse environmental effect 

will result from emissions from any 

source.’’ This language could be read to 

provide that the Agency consider only 

the risks associated with the source 

category at issue, and ignore how those 

risks fit with real-world exposures.304

However, the language could also be 

read to provide that the Agency 

consider the cumulative effect of HAP 

emissions from the individual sources 

in the category in conjunction with the 

HAP emissions from other sources. The 

latter is a reasonable interpretation, 

especially when considering how the 

public is exposed to HAP emissions. 

Considering the individual sources in a 

source category in isolation treats the 

sources as if they exist in a vacuum, 

which does not mirror reality. Such an 

approach is particularly problematic for 

environmentally persistent HAP that 

bio-accumulate in the food chain, such 

as mercury.305

Here, the record demonstrates that 98 

percent of the watersheds EPA modeled 

have total exposures to MeHg that 

exceed the MeHg RfD, above which 

there is increased risk of adverse effects 

on human health, especially on the 

developing nervous systems of children 

during gestation. EGUs remain one of 

the largest unregulated sources of Hg 

emissions, and those emissions 

continue to contribute to Hg exposures 

and risk. UARG seeks to ignore the fact 

that exposures above the RfD exist in 

almost every watershed we modeled, 

and instead focuses on the contribution 

provided solely by EGUs. The EPA did 

as UARG asked and found that up to 10 

percent of modeled watersheds where 

deposition from U.S. EGUs alone leads 

to potential exposures that exceed the 

MeHg RfD. Thus, even focusing on EGU 

emissions in a vacuum, which we do 

not believe is appropriate or required 

under CAA section 112(c)(9), we still 

found that up to 10 percent of the 

watersheds exceed the RfD due to EGU 

emissions even before taking into 

account the numerous other sources of 

Hg deposition, and we believe this to be 

an unacceptable percentage of 

watersheds above the RfD. Due to the 

persistent, bioacccumulative nature of 

Hg, among other factors, we believe it is 

appropriate to consider the combined 

impact of Hg emissions from EGUs and 

other sources of Hg. Thus, we also 

considered the 24 percent of modeled 

watersheds where, even though U.S. 

EGU emissions alone are not enough to 

cause exposures that exceed the RfD, 

those emissions contribute at least 5 

percent of total exposures to MeHg that 

exceed the RfD. The combined total of 

29 percent of modeled watersheds 

where U.S. EGUs cause or contribute to 

MeHg exposures above the RfD is 

clearly unacceptable and thus the UARG 

petition to delist must be denied. 

Thus, the technical analyses the 

Agency conducted in support of the 

appropriate and necessary finding 

confirm that EGUs should remain a 

listed source category. 

V. Summary of This Final NESHAP 

This section summarizes the 

requirements of the final EGU NESHAP. 

Section VI below summarizes the 

significant changes to this final rule 

following proposal. 

A. What is the source category regulated 

by this final rule? 

This final rule affects coal- and oilfired EGUs. 

B. What is the affected source? 

An existing affected source under this 

final rule is the collection of coal- or oilfired EGUs in a subcategory within a 

single contiguous area and under 

common control. A new affected source 

is each coal- or oil-fired EGU for which 

construction or reconstruction began 

after May 3, 2011. 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9367 

CAA section 112(a)(8) defines an EGU as: 

a fossil fuel-fired combustion unit of more 

than 25 megawatts that serves a generator 

that produces electricity for sale. A unit that 

cogenerates steam and electricity and 

supplies more than one-third of its potential 

electric output capacity and more than 25 

megawatts electrical output to any utility 

power distribution system for sale shall be 

considered an electric utility steam 

generating unit. 

If an EGU burns coal (either as a 

primary fuel or as a supplementary fuel) 

or any combination of coal with another 

fuel (except for solid waste as noted 

below) where the coal accounts for more 

than 10.0 percent of the average annual 

heat input during any 3 consecutive 

calendar years or for more than 15.0 

percent of the annual heat input during 

any one calendar year after the 

applicable compliance date, the unit is 

considered to be coal-fired under this 

final rule. 

If a unit is not a coal-fired unit and 

burns only oil or burns oil in 

combination with a fuel other than coal 

(except solid waste as noted below) 

where the oil accounts for more than 

10.0 percent of the average annual heat 

input during any 3 consecutive calendar 

years or for more than 15.0 percent of 

the annual heat input during any one 

calendar year after the applicable 

compliance date, the unit is considered 

to be oil-fired under this final rule. 

As noted below, the EPA is finalizing 

in this rule a definition to determine 

whether the combustion unit is ‘‘fossil 

fuel fired’’ such that it is considered an 

EGU as defined in CAA section 

112(a)(8) and, thus, potentially subject 

to this final rule. In addition, using the 

construct of the definition of ‘‘oil-fired’’ 

from the ARP, we are finalizing in this 

rule a requirement that the unit fire coal 

or oil (or natural gas), or any 

combination thereof, for more than 10.0 

percent of the average annual heat input 

during any 3 consecutive calendar years 

or for more than 15.0 percent of the 

annual heat input during any one 

calendar year to be considered a ‘‘fossil 

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 an EGU co-fires limited amounts 

of either coal or oil with natural gas or 

other non-fossil fuels (e.g., biomass). 

If an EGU combusts solid waste, 

standards issued pursuant to CAA 

section 129 apply to that EGU, rather 

than this final rule. 

C. What are the pollutants regulated by 

this final rule? 

For coal-fired EGUs, this final rule 

regulates HCl as a surrogate for acid gas 

HAP, with an alternate of SO2 as a 

surrogate for acid gas HAP for coal-fired 

EGUs with FGD systems installed and 

operational; filterable PM as a surrogate 

for non-mercury HAP metals, with total 

non-mercury HAP metals and 

individual non-mercury HAP metals as 

alternative equivalent standards; Hg; 

and organic HAP. For oil-fired EGUs, 

this final rule regulates HCl and HF; 

filterable PM as a surrogate for total 

HAP metals, with individual HAP 

metals as alternative equivalent 

standards; and organic HAP. 

D. What emission limits and work 

practice standards must I meet and 

what are the subcategories in the final 

rule? 

We are finalizing the emission 

limitations presented in Tables 3 and 4 

of this preamble. Within the two major 

subcategories of ‘‘coal’’ and ‘‘oil,’’ 

emission limitations were developed for 

new and existing sources for seven 

subcategories, two for coal-fired EGUs, 

one for IGCC EGUs burning synthetic 

gas derived from coal- and/or solid oilderived fuel, one for solid oil-derived 

fuel-fired EGUs, and four for liquid oilfired EGUs, as described in more detail 

below. The limited-use liquid oil-fired 

subcategory, discussed elsewhere in this 

preamble, is not presented in Table 3 

because only work practice standards 

apply to this subcategory. 

TABLE 3—EMISSION LIMITATIONS FOR COAL-FIRED AND SOLID OIL-DERIVED FUEL-FIRED EGUS

Subcategory Filterable particulate matter 

Hydrogen 

chloride Mercury 

Existing—Unit not low rank virgin coal ............................................................................... 3.0E–2 lb/

MMBtu.

(3.0E–1 lb/MWh) 

2.0E–3 lb/ 

MMBtu.

(2.0E–2 lb/MWh) 

1.2E0 lb/TBtu. 

(1.3E–2 lb/ 

GWh). 

Existing—Unit designed low rank virgin coal ..................................................................... 3.0E–2 lb/ 

MMBtu.

(3.0E–1 lb/MWh) 

2.0E–3 lb/ 

MMBtu.

(2.0E–2 lb/MWh) 

1.1E+1 lb/TBtu. 

(1.2E–1 lb/ 

GWh). 

4.0E0 lb/TBtu a. 

(4.0E–2 lb/ 

GWh a). 

Existing—IGCC ................................................................................................................... 4.0E–2 lb/ 

MMBtu.

(4.0E–1 lb/MWh) 

5.0E–4 lb/ 

MMBtu.

(5.0E–3 lb/MWh) 

2.5E0 lb/TBtu. 

(3.0E–2 lb/ 

GWh). 

Existing—Solid oil-derived .................................................................................................. 8.0E–3 lb/ 

MMBtu.

(9.0E–2 lb/MWh) 

5.0E–3 lb/ 

MMBtu.

(8.0E–2 lb/MWh) 

2.0E–1 lb/TBtu. 

(2.0E–3 lb/ 

GWh). 

New—Unit not low rank virgin coal .................................................................................... 7.0E–3 lb/MWh 4.0E–4 lb/MWh 2.0E–4 lb/GWh. 

New—Unit designed for low rank virgin coal ..................................................................... 7.0E–3 lb/MWh 4.0E–4 lb/MWh 4.0E–2 lb/GWh. 

New—IGCC ........................................................................................................................ 7.0E–2 lb/MWh b

9.0E–2 lb/MWh c

2.0E–3 lb/MWh d 3.0E–3 lb/ 

GWh e. 

New—Solid oil-derived ....................................................................................................... 2.0E–2 lb/MWh 4.0E–4 lb/MWh 2.0E–3 lb/GWh. 

Note: lb/MMBtu = pounds pollutant per million British thermal units fuel input. 

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

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

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

aBeyond-the-floor limit as discussed elsewhere. 

b Duct burners on syngas; based on permit levels in comments received. 


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9368 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

c Duct burners on natural gas; based on permit levels in comments received. 

dBased on best-performing similar source. 

eBased on permit levels in comments received. 

TABLE 4—EMISSION LIMITATIONS FOR LIQUID OIL-FIRED EGUS

Subcategory Filterable particulate 

matter 

Hydrogen 

chloride 

Hydrogen 

fluoride 

Existing—Liquid oil—continental ........................................................................ 3.0E–2 lb/MMBtu ...

(3.0E–1 lb/MWh) ....

2.0E–3 lb/MMBtu ...

(1.0E–2 lb/MWh) ....

4.0E–4 lb/MMBtu. 

(4.0E–3 lb/MWh). 

Existing—Liquid oil—non-continental ................................................................. 3.0E–2 lb/MMBtu ...

(3.0E–1 lb/MWh) ....

2.0E–4 lb/MMBtu ...

(2.0E–3 lb/MWh) ....

6.0E–5 lb/MMBtu. 

(5.0E–4 lb/MWh). 

New—Liquid oil—continental .............................................................................. 7.0E–2 lb/MWh ...... 4.0E–4 lb/MWh ...... 4.0E–4 lb/MWh. 

New—Liquid oil—non-continental ....................................................................... 2.0E–1 lb/MWh ...... 2.0E–3 lb/MWh ...... 5.0E–4 lb/MWh. 

We are also finalizing alternate 

equivalent emission standards (for 

certain subcategories) to the final 

surrogate standards in three areas: SO2

(for HCl), individual non-mercury 

metals and total non-mercury metals 

(for filterable PM) from coal- and solid 

oil-derived fuel-fired EGUs, and 

individual and total metals (for 

filterable PM) from oil-fired EGUs. The 

final alternate emission limitations are 

provided in Tables 5 and 6 of this 

preamble. 

TABLE 5—ALTERNATE EMISSION LIMITATIONS FOR EXISTING COAL- AND OIL-FIRED EGUS

Subcategory/Pollutant Coal-fired EGUs IGCC Liquid oil, continental 

Liquid oil, non-continental Solid oilderived 

SO2 ............................................. 2.0E–1 lb/MMBtu ...

(1.5E0 lb/MWh) ......

NA .......................... NA .......................... NA .......................... 3.0E–1 lb/MMBtu. 

(2.0E0 lb/MWh). 

Total non-mercury metals .......... 5.0E–5 lb/MMBtu ...

(5.0E–1 lb/GWh) ....

6.0E–5 lb/MMBtu ...

(5.0E–1 lb/GWh) ....

8.0E–4 lb/MMBtu ...

(8.0E–3 lb/MWh) a ..

6.0E–4 lb/MMBtu ...

(7.0E–3 lb.MWh) a ..

4.0E–5 lb/MMBtu. 

(6.0E–1 lb/GWh). 

Antimony, Sb .............................. 8.0E–1 lb/TBtu .......

(8.0E–3 lb/GWh) ....

1.4E0 lb/TBtu .........

(2.0E–2 lb/GWh) ....

1.3E+1 lb/TBtu .......

(2.0E–1 lb/GWh) ....

2.2E0 lb/TBtu .........

(2.0E–2 lb/GWh) ....

8.0E–1 lb/TBtu. 

(8.0E–3 lb/GWh). 

Arsenic, As ................................. 1.1E0 lb/TBtu .........

(2.0E–2 lb/GWh) ....

1.5E0 lb/TBtu .........

(2.0E–2 lb/GWh) ....

2.8E0 lb/TBtu .........

(3.0E–2 lb/GWh) ....

4.3E0 lb/TBtu .........

(8.0E–2 lb/GWh) ....

3.0E–1 lb/TBtu. 

(5.0E–3 lb/GWh). 

Beryllium, Be .............................. 2.0E–1 lb/TBtu .......

(2.0E–3 lb/GWh) ....

1.0E–1 lb/TBtu .......

(1.0E–3 lb/GWh) ....

2.0E–1 lb/TBtu .......

(2.0E–3 lb/GWh) ....

6.0E–1 lb/TBtu .......

(3.0E–3 lb/GWh) ....

6.0E–2 lb/TBtu. 

(6.0E–4 lb/GWh). 

Cadmium, Cd ............................. 3.0E–1 lb/TBtu .......

(3.0E–3 lb/GWh) ....

1.5E–1 lb/TBtu .......

(2.0E–3 lb/GWh) ....

3.0E–1 lb/TBtu .......

2.0E–3 lb/GWh) .....

3.0E–1 lb/TBtu .......

(3.0E–3 lb/GWh) ....

3.0E–1 lb/TBtu. 

(4.0E–3 lb/GWh). 

Chromium, Cr ............................. 2.8E0 lb/TBtu .........

(3.0E–2 lb/GWh) ....

2.9E0 lb/TBtu .........

(3.0E–2 lb/GWh) ....

5.5E0 lb/TBtu .........

(6.0E–2 lb/GWh) ....

3.1E+1 lb/TBtu .......

(3.0E–1 lb/GWh) ....

8.0E–1 lb/TBtu. 

(2.0E–2 lb/GWh). 

Cobalt, Co .................................. 8.0E–1 lb/TBtu .......

(8.0E–3 lb/GWh) ....

1.2E0 lb/TBtu .........

(2.0E–2 lb/GWh) ....

2.1E+1 lb/TBtu .......

(3.0E–1 lb/GWh) ....

1.1E+2 lb/TBtu .......

(1.4E0 lb/GWh) ......

1.1E0 lb/TBtu. 

(2.0E–2 lb/GWh). 

Lead, Pb ..................................... 1.2E0 lb/TBtu .........

(2.0E–2 lb/GWh) ....

1.9E+2 lb/MMBtu ...

(1.8E0 lb/MWh) ......

8.1E0 lb/TBtu .........

(8.0E–2 lb/GWh) ....

4.9E0 lb/TBtu .........

(8.0E–2 lb/GWh) ....

8.0E–1 lb/TBtu. 

(2.0E–2 lb/GWh). 

Manganese, Mn ......................... 4.0E0 lb/TBtu .........

(5.0E–2 lb/GWh .....

2.5E0 lb/TBtu .........

(3.0E–2 lb/GWh) ....

2.2E+1 lb/TBtu .......

(3.0E–1 lb/GWh) ....

2.0E+1 lb/TBtu .......

(3.0E–1 lb/GWh) ....

2.3E0 lb/TBtu. 

(4.0E–2 lb/GWh). 

Mercury, Hg ............................... NA .......................... NA .......................... 2.0E–1 lb/TBtu .......

(2.0E–3 lb/GWh) ....

4.0E–2 lb/TBtu 

(4.0E–4 lb/GWh).

NA. 

Nickel, Ni .................................... 3.5E0 lb/TBtu .........

(4.0E–2 lb/GWh) ....

6.5E0 lb/TBtu .........

(7.0E–2 lb/GWh) ....

1.1E+2 lb/TBtu .......

(1.1E0 lb/GWh) ......

4.7E+2 lb/TBtu .......

(4.1E0 lb/GWh) ......

9.0E0 lb/TBtu. 

(2.0E–1 lb/GWh). 

Selenium, Se .............................. 5.0E0 lb/TBtu .........

(6.0E–2 lb/GWh) ....

2.2E+1 lb/TBtu .......

(3.0E–1 lb/GWh) ....

3.3E0 lb/TBtu .........

(4.0E–2 lb/GWh) ....

9.8E0 lb/TBtu .........

(2.0E–1 lb/GWh) ....

1.2E0 lb/TBtu. 

(2.0E–2 lb/GWh). 

NA = Not applicable. 

a Includes Hg. 

TABLE 6—ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OIL-FIRED EGUS

Subcategory/Pollutant Coal-fired EGUs IGCC a

Liquid oil, 

continental, 

lb/GWh 

Liquid oil, 

non-continental, 

lb/GWh 

Solid 

oilderived 

SO2 ............................................. 4.0E–1 lb/MWh ...... 4.0E–1 lb/MWh ...... NA .......................... NA .......................... 4.0E–1 lb/MWh 

Total non-mercury metals .......... 6.0E–2 lb/GWh ...... 4.0E–1 lb/GWh ...... 2.0E–4 lb/MWh b .... 7.0E–3 lb/MWh b .... 6.0E–1 lb/GWh 

Antimony, Sb .............................. 8.0E–3 lb/GWh ...... 2.0E–2 lb/GWh ...... 1.0E–2 ................... 8.0E–3 ................... 8.0E–3 lb/GWh 

Arsenic, As ................................. 3.0E–3 lb/GWh ...... 2.0E–2 lb/GWh ...... 3.0E–3 ................... 6.0E–2 ................... 3.0E–3 lb/GWh 

Beryllium, Be .............................. 6.0E–4 lb/GWh ...... 1.0E–3 lb/GWh ...... 5.0E–4 ................... 2.0E–3 ................... 6.0E–4 lb/GWh 

Cadmium, Cd ............................. 4.0E–4 lb/GWh ...... 2.0E–3 lb/GWh ...... 2.0E–4 ................... 2.0E–3 ................... 7.0E–4 lb/GWh 

Chromium, Cr ............................. 7.0E–3 lb/GWh ...... 4.0E–2 lb/GWh ...... 2.0E–2 ................... 2.0E–2 ................... 6.0E–3 lb/GWh 

Cobalt, Co .................................. 2.0E–3 lb/GWh ...... 4.0E–3 lb/GWh ...... 3.0E–2 ................... 3.0E–1 ................... 2.0E–3 lb/GWh 

Lead, Pb ..................................... 2.0E–3 lb/GWh ...... 9.0E–3 lb/GWh ...... 8.0E–3 ................... 3.0E–2 ................... 2.0E–2 lb/GWh 

Mercury, Hg ............................... NA .......................... NA .......................... 1.0E–4 ................... 4.0E–4 ................... 2.0E–3 lb/GWh 

Manganese, Mn ......................... 4.0E–3 lb/GWh ...... 2.0E–2 lb/GWh ...... 2.0E–2 ................... 1.0E–1 ................... 7.0E–3 lb/GWh 


srobinson on DSK4SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9369 

306We would also note that the EPA, as a part of 

the Industrial Boiler MACT reconsideration 

proposal that was signed on December 2, 2011, is 

proposing to establish work practice standards for 

control of dioxins and furans from industrial 

boilers. 

307ASTM Method D388–05, ‘‘Standard 

Classification of Coals by Rank’’ (incorporated by 

reference, see § 63.14). 

308U.S. Department of Energy, Wabash River Coal 

Gaification Repowering Project. Project 

Performance Summary; Clean Coal Technology 

Demonstration Program. DOE/FE–0448. July 2002. 

EPA–HQ–OAR–2009–0234–2933. 

TABLE 6—ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OIL-FIRED EGUS—Continued 

Subcategory/Pollutant Coal-fired EGUs IGCC a

Liquid oil, 

continental, 

lb/GWh 

Liquid oil, 

non-continental, 

lb/GWh 

Solid 

oilderived 

Nickel, Ni .................................... 4.0E–2 lb/GWh ...... 7.0E–2 lb/GWh ...... 9.0E–2 ................... 4.1E0 ..................... 4.0E–2 lb/GWh 

Selenium, Se .............................. 6.0E–3 lb/GWh ...... 3.0E–1 lb/GWh ...... 2.0E–2 ................... 2.0E–2 ................... 6.0E–3 lb/GWh 

NA = Not applicable. 

aBased on best-performing similar source. 

b Includes Hg. 

As noted elsewhere in this preamble, 

we are finalizing a requirement to use 

filterable PM as a surrogate for the nonmercury metallic HAP and HCl as a 

surrogate for the acid gas HAP for all 

subcategories of coal-fired EGUs and for 

the solid oil derived fuel-fired EGUs. 

For all liquid oil-fired EGUs, we are 

finalizing a requirement to use filterable 

PM as a surrogate for the total metallic 

HAP, and we are finalizing HCl and HF 

limits. 

In addition, we are finalizing 

alternative standards for certain HAP for 

some subcategories. The alternative 

pollutants and subcategories are as 

follows: (1) SO2 as a surrogate to HCl for 

all subcategories with add-on FGD 

systems (except liquid oil-fired 

subcategories as there were no existing 

units from which to base an alternate 

SO2 limit); (2) individual non-mercury 

metallic HAP as an alternate to filterable 

PM for all subcategories (except that it 

includes Hg for liquid oil-fired 

subcategories); and (3) total nonmercury metallic HAP as an alternate to 

filterable PM for all subcategories 

(except that it includes Hg for liquid oilfired subcategories). These alternative 

standards are discussed elsewhere in 

this preamble. 

We are finalizing a beyond-the-floor 

standard for Hg only for all existing 

coal-fired units designed for low rank 

virgin coal based on the use of activated 

carbon injection (ACI) for Hg control, as 

described elsewhere in this preamble. 

The EPA has determined that this 

beyond-the-floor level is achievable 

after considering the relevant CAA 

section 112(d)(2) provisions. 

As noted elsewhere in this preamble, 

we are also finalizing a compliance 

assurance option that would allow you 

to monitor liquid oil fuel moisture to 

demonstrate that fuel moisture content 

is no greater than 1.0 percent. Provided 

that demonstration is made, you will 

not have to conduct additional testing 

and monitoring to demonstrate 

compliance with the HCl and HF 

emission limits for units in both liquid 

oil subcategories (i.e., continental and 

non-continental). 

Pursuant to CAA section 112(h), we 

are finalizing a work practice standard 

for organic HAP, including emissions of 

dioxins and furans, for all subcategories 

of EGUs. The work practice standard 

being finalized requires the 

implementation of periodic burner tuneup 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.306 We believe that a work practice 

standard will lead to a better 

environmental outcome than would be 

obtained through a requirement to 

measure a pollutant for which results 

may or may not be obtained. We believe 

that the work practice standard will 

result in actions being taken that will 

reduce emissions of these HAP. 

In addition, as discussed below, we 

are creating a subcategory for limited 

use liquid oil-fired electric utility steam 

generating unit with an annual capacity 

factor of less than 8 percent of its 

maximum or nameplate heat input and 

we are establishing work practice 

standards applicable to such units 

pursuant to CAA section 112(h). 

We are finalizing that new or existing 

EGUs are ‘‘coal-fired’’ if they combust 

coal more than 10 percent of the average 

annual heat input during any 3 

consecutive calendar years or for more 

than 15 percent of the annual heat input 

during any one calendar year and meet 

the final definition of ‘‘fossil fuel-fired.’’ 

We are finalizing that an EGU is 

considered to be in the coal-fired ‘‘unit 

designed for coal greater than or equal 

to 8,300 Btu/lb’’ subcategory if the EGU: 

(1) meets the final definitions of ‘‘fossil 

fuel-fired’’ and ‘‘coal-fired electric 

utility steam generating unit;’’ and (2) is 

not a coal-fired EGU in the ‘‘unit 

designed for low rank virgin coal’’ 

subcategory. 

We are finalizing that the EGU is 

considered to be in the ‘‘unit designed 

for low rank virgin coal’’ subcategory if 

the EGU: (1) meets the final definitions 

of ‘‘fossil fuel-fired’’ and ‘‘coal-fired 

electric utility steam generating unit;’’ 

and (2) is designed to burn and is 

burning nonagglomerating virgin coal 

having a calorific value (moist, mineral 

matter-free basis) of less than 19,305 kJ/ 

kg (8,300 Btu/lb) and that is constructed 

and operates at or near the mine that 

produces such coal.307

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 oilderived fuel (e.g., petroleum coke, pet 

coke), (2) meets the final definition of 

‘‘fossil fuel-fired,’’ and (3) is classified 

as an IGCC unit. We are not 

subcategorizing IGCC EGUs based on 

the source of the syngas used (e.g., coal, 

petroleum coke). Based on information 

available to the Agency, although the 

fuel characteristics of coal and petcoke 

are quite different, the syngas products 

from both feedstocks have similar HAP 

content and similar HAP emissions 

characteristics that can be controlled in 

a similar manner.308

We are finalizing that the EGU is 

considered to be in the ‘‘Continental 

liquid oil-fired’’ subcategory if (1) meets 

the final definitions of ‘‘oil-fired electric 

utility steam generating unit’’ and 

‘‘fossil fuel-fired;’’ and (2) is located in 

the continental United States (U.S.). 

We are finalizing that the EGU is 

considered to be ‘‘Non-continental 

liquid oil-fired’’ subcategory if (1) meets 

the final definitions of ‘‘oil-fired electric 

utility steam generating unit’’ and 


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‘‘fossil fuel-fired;’’ and (2) is located 

outside continental U.S. 

We are finalizing that the EGU is 

considered to be ‘‘solid oil-derived fuelfired’’ if (1) the EGU is not a coal-fired 

EGU and burns solid oil-derived fuel 

(e.g., petroleum coke, pet coke); and (2) 

meets the final definitions of ‘‘oil-fired 

electric utility steam generating unit’’ 

and ‘‘fossil fuel-fired.’’ 

We are finalizing that the EGU is 

considered to be a ‘‘limited-use liquid 

oil-fired’’ if (1) the EGU meets the final 

definitions of ‘‘oil-fired electric utility 

steam generating unit’’ and ‘‘fossil fuelfired;’’ and (2) has an annual capacity 

factor of less than 8 percent of its 

maximum or nameplate heat input, 

whichever is greater, averaged over a 24- 

month block contiguous period 

commencing. 

E. What are the requirements during 

periods of startup, shutdown, and 

malfunction? 

As discussed below in section VI.E., 

for startup and shutdown, the 

requirements have changed since 

proposal. For periods of startup and 

shutdown, the EPA is finalizing work 

practice standards in lieu of numeric 

emission limits. Numeric emission 

limits apply for all other periods for all 

pollutants, except organic HAP. For 

malfunctions, the EPA is finalizing an 

affirmative defense for exceedances of 

the numerical emission limits that are 

caused by malfunctions. 

F. What are the testing and initial 

compliance requirements? 

We are requiring that you, as an 

owner or operator of a new or existing 

coal- or oil-fired EGU, must conduct 

performance tests to demonstrate 

compliance with all applicable emission 

limits. For units using certified 

continuous emissions monitoring 

systems (CEMS) that directly measure 

the regulated pollutant under final 40 

CFR part 63, subpart UUUUU (e.g., Hg 

CEMS, HCl CEMS, HF CEMS, SO2

CEMS (where an SO2 limit applies as 

the alternative equivalent standard)), or 

sorbent trap monitoring systems, the 

initial performance test consists of all 

valid data recorded with the certified 

monitoring system in the first 30 boiler 

operating days of data collected with the 

certified monitoring system prior to the 

initial compliance demonstration date 

specified in § 63.10005. A source may 

also elect to use a PM CEMS to 

demonstrate compliance with the 

filterable PM emission limit. If this 

option is selected, then the same 

provisions as noted above for other 

CEMS will apply. (Note that EPA 

anticipates that the PM monitoring 

device that may most often will be used 

is a PM continuous parameter 

monitoring system (CPMS) in 

conjunction with an operating limit, as 

more fully described below.) For units 

and pollutants not being monitored via 

CEMS, the owner or operator of an 

affected unit must perform the initial 

performance testing in accordance with 

established EPA reference test methods 

or the voluntary consensus standard 

methods incorporated by reference. 

You, as the owner or operator of an 

affected unit, must conduct the 

following compliance tests where 

applicable: 

(1) For coal-fired units, IGCC units, 

and solid oil-derived fuel-fired units, if 

you elect to comply with the filterable 

PM emission limit, you must conduct 

filterable PM emissions testing using 

EPA Method 5 from Appendix A to part 

60 of chapter 40 to determine initial 

compliance. Alternatively, if you elect 

to comply with the total non-mercury 

HAP metals emission limit or the 

individual non-mercury HAP metals 

emissions limits, you must conduct 

HAP metals testing using EPA Method 

29 from Appendix A to part 60 of 

chapter 40. Note for this rule that the 

filter temperature for each Method 5 or 

29 emissions test must be maintained at 

160° ± 14 °C (320 ° ± 25 °F), 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 oilderived fuel-fired units, you must use a 

Hg CEMS or a sorbent trap monitoring 

system for both initial compliance and 

continuous compliance using the 

continuous Hg monitoring provisions of 

Appendix A to 40 CFR part 63, subpart 

UUUUU, except where the low emitting 

EGU (LEE) requirements apply (see 

below). The initial performance test 

consists of all valid data recorded with 

the certified Hg monitoring system in 

the 30 boiler operating days of data 

collected with the certified monitoring 

system by the initial compliance 

demonstration date specified in 

§ 63.10005. 

(3) For coal-fired and solid oil-derived 

fuel-fired units and new or 

reconstructed IGCC units that employ 

FGD technology and elect to meet the 

alternative SO2 limit in place of the HCl 

limit, you need not conduct an initial 

stack test for HCl or SO2. Instead, the 30 

boiler operating days of data collected 

with the certified SO2 CEMS by the 

initial compliance demonstration date 

specified in § 63.10005 are used to 

determine initial compliance, and the 

SO2 CEMS is used thereafter to 

demonstrate continuous compliance. If 

you instead opt to meet the HCl limit 

and use an HCl CEMS for compliance, 

you need not conduct an initial stack 

test for HCl. Instead, the 30 boiler 

operating days of data collected with the 

certified HCl CEMS by the initial 

compliance demonstration date 

specified in § 63.10005 are used to 

determine initial compliance. For units 

not using the SO2 or HCl CEMS options, 

you must conduct an initial stack test 

for HCl using EPA Method 26, 26A, or 

320 from Appendix A to part 60 of 

chapter 40. You may use EPA Method 

26 or 320 or ASTM Method D6348–03 

(Reapproved 2010) with additional 

quality assurance if no entrained water 

droplets exist in the exhaust gas, but 

you must use Method 26A if entrained 

water droplets exist in the exhaust gas. 

(4) For liquid oil-fired units, you must 

conduct initial performance testing as 

follows. If you elect to meet the 

filterable PM limit instead of the nonmercury metals limit (total or 

individual), then use Method 5 with the 

filter material maintained at 160° ± 14°C 

(320° ± 25°F). Alternatively, you may 

use a PM CEMS as discussed elsewhere 

in this preamble. If you elect to meet 

either the total or individual HAP 

metals limit, you will use Method 29 for 

all non-mercury HAP metals. For Hg, 

conduct emissions testing using EPA 

Method 29 or 30B from Appendix A to 

part 60 of chapter 40, or ASTM Method 

D6784–02 (Reapproved 2008). For acid 

gases, conduct HCl and HF testing using 

EPA Method 26A, 320, or 26; or you 

may elect to comply by using an HCl 

CEMS and/or an HF CEMS; or under 

certain conditions you may choose to 

demonstrate compliance by measuring 

fuel moisture to demonstrate that 

moisture content is no greater than 1.0 

percent. You must measure daily if fuel 

is delivered continuously or per 

shipment if fuel is delivered on a batch 

basis, or you may use a fuel moisture 

content certification provided by your 

fuel supplier. If you use a CEMS, then 

use the 30 boiler operating days of data 

collected with the certified monitoring 

system by the initial compliance 

demonstration date specified in 

§ 63.10005 to determine initial 

compliance. 

(5) For the required performance stack 

tests, if you are demonstrating 

compliance with a heat-input based 

standard, you must conduct concurrent 

O2 or carbon dioxide (CO2) emission 

testing using EPA Method 3A or 3B 

from appendix A to part 60 of chapter 

40 or ANSI/ASME PTC 19.10–1981 and 

then use an appropriate equation, 

selected from among Equations 19–1 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9371 

through 19–9 in EPA Method 19 from 

appendix A to part 60 of chapter 40, to 

convert measured pollutant 

concentrations to lb/MMBtu values. 

Multiply the lb/MMBtu value by one 

million to get the lb/TBtu value (where 

applicable). If you choose to meet an 

electrical output-based emissions limit, 

you must also collect concurrent stack 

gas flow rate and electrical production 

data. 

(6) For an existing unit that you 

believe will qualify as LEE for Hg, you 

must conduct an initial Method 30B test 

over 30 days and follow the calculation 

procedures in the final rule to document 

a potential to emit less than 10 percent 

of the applicable Hg emissions limit or 

less than 29 pounds of Hg per year. If 

your unit qualifies as a LEE for Hg, you 

must conduct subsequent performance 

tests on an annual basis to demonstrate 

that the unit continues to qualify. For all 

other pollutants, you must conduct the 

initial compliance test, and then all 

other required tests over a 3-year period, 

and in all such tests, your emission 

results must be less than 50 percent of 

the applicable emission limit. If you 

qualify as a LEE on that basis, you must 

conduct subsequent performance tests 

every 3 years to demonstrate that the 

unit continues to qualify. 

(7) You may use results from tests 

conducted no earlier than 12 months 

before the compliance date of this rule 

as the initial performance test for an 

applicable pollutant, provided that: 

a. You certify and keep records 

demonstrating that no significant 

changes have occurred, 

b. Tests were conducted using 

methods allowed in this rule in 

accordance with § 63.10007 and Table 5, 

c. You have records of all parameters 

needed to convert results to units of the 

standard for the entire period, and 

d. For a CEMS-based performance 

test, you have all the required data for 

the entire 30-boiler operating day rolling 

average period. 

Operating Limit for PM CEMS 

Under the final rule, you may elect to 

comply continuously with an operating 

limit, established during the initial 

performance test, to demonstrate 

continuous compliance with the 

filterable PM, total non-mercury HAP 

metals, or individual non-mercury HAP 

metals limit. You will use a PM CPMS 

to monitor compliance with the 

operating limit. The PM CPMS 

operating principle must be based on instack or extractive light scatter, light 

scintillation, beta attenuation, or mass 

accumulation detection of the exhaust 

gas or representative exhaust gas 

sample. The reportable measurement 

output from the PM CPMS may be 

expressed as milliamps, stack 

concentration, or other raw data signal. 

Meeting the operating limit serves as 

your demonstration of continuous 

compliance with the filterable PM, total 

non-mercury HAP metals, or individual 

non-mercury HAP metals limit. As 

mentioned earlier, if you use this 

method to demonstrate continuous 

compliance, you must install a PM 

CPMS and establish the operating limit 

during the initial compliance test for 

filterable PM, total non-mercury HAP 

metals, or individual non-mercury HAP 

metals. As noted below, when you use 

this operating limit, you can reduce 

stack testing frequency to demonstrate 

ongoing compliance. You may also opt 

to install and operate a PM CEMS 

certified in accordance with 

Performance Specification 11 and 

Procedure 2 of 40 CFR part 60, 

Appendices B and F, respectively. If you 

elect to use this option, then the 

requirements for quarterly testing with 

Method 5, or annual testing and use of 

a PM CPMS, are no longer applicable. 

Dioxins/Furans and Non-Dioxin/Furan 

Organic HAP 

For dioxins and furans and nondioxin/furan organic HAP, you must 

submit documentation that you have 

conducted a combustion process tuneup, a thorough equipment inspection, 

and an optimization to minimize 

generation of CO and NOX, all meeting 

the requirements of this final rule. The 

work practice standard involves 

maintaining and inspecting the burners 

and associated combustion controls, 

tuning the specific burner type to 

optimize combustion, obtaining and 

recording CO and NOX values before 

and after burner adjustments, keeping 

records of activity and measurements, 

and submitting a report for each tuneup conducted. You must collect CO and 

NOX data and may use portable 

analyzers (which include handheld or 

similar devices) to monitor and verify 

the results. The specific details are 

addressed in 40 CFR 63.10021 of the 

final rule. 

This same work practice standard also 

applies in place of any emission limits 

for Hg, non-mercury metals HAP, acid 

gas HAP, dioxins and furans, and nondioxin/furan organic HAP from a 

limited-use, liquid oil-fired EGU (i.e., a 

unit that has an annual capacity factor 

on oil of less than 8 percent of its 

maximum or nameplate heat input, 

whichever is greater). The EPA 

established this subcategory in response 

to comments and a further analysis of 

the units within this subcategory in the 

ICR database. For these units, EPA 

believes that the required work practice 

standards are appropriate and consistent 

with the requirement of CAA section 

112(h). 

G. What are the continuous compliance 

requirements? 

To demonstrate continuous 

compliance with the emission 

limitations, the final rule includes the 

following requirements: 

(1) Use of CEMS. Where a CEMS or a 

sorbent trap monitoring system is used 

for demonstrating initial compliance, 

you also must use the CEMS or sorbent 

trap monitoring system on a continuous 

basis to demonstrate ongoing 

compliance with the numerical 

emission limits. CEMS or sorbent trap 

monitoring system data are not used to 

determine compliance with the work 

practice standards applicable during 

periods of startup and shutdown, but 

sources that install a CEMS or a sorbent 

trap monitoring system to demonstrate 

compliance with the numerical 

emission limits must operate the system 

at all times, as EPA intends to evaluate 

the continuous monitoring data from 

start-up and shutdown periods as 

discussed below. You must calculate a 

rolling average for each successive 30- 

boiler operating day rolling average 

period. All valid data collected during 

each successive period will be used to 

demonstrate compliance, except for data 

collected during periods of startup and 

shutdown; during those periods, the 

owner or operator must meet work 

practice requirements instead of the 

numerical emission limits. There is no 

numerical minimum data availability 

required to constitute a valid 30-boiler 

operating day rolling average; however, 

you must monitor at all times that the 

process is in operation (including 

during startups and shutdowns, 

although emissions during these periods 

are not included in the 30-boiler 

operating day average). You must 

operate, maintain, and quality-assure 

the CEMS or sorbent trap monitoring 

systems in accordance with the 

provisions in 40 CFR 63.10010 and 

Appendix A and B of the final rule (for 

Hg, HCl, and HF CEMS), in accordance 

with Performance Specification 11 in 

Appendix B to 40 CFR part 60 and 

Procedure 2 in Appendix F to part 60 

(for PM CEMS used for direct 

compliance), or in accordance with 40 

CFR part 75 (for SO2 CEMS, and certain 

ancillary monitors such as a diluent or 

moisture monitor). 

For each unit using HCl, HF, SO2, PM, 

or Hg CEMS or a sorbent trap 

monitoring system for continuous 

compliance, you must install, certify, 

maintain, operate and quality-assure the 


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9372 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

additional CEMS (e.g., CEMS that 

measure O2 or CO2 concentration, stack 

gas flow rate, and, if default moisture 

values are not used, moisture content) 

needed to convert pollutant 

concentrations to units of the emission 

standards or operating limits. Where 

appropriate, you must certify and 

quality-assure these additional CEMS 

according to 40 CFR part 75. 

For HCl and HF CEMS, the EPA is 

adding monitoring provisions as 

Appendix B to 40 CFR part 63, subpart 

UUUUU. Appendix A references 

performance specification (PS) 15 of 

Appendix B to 40 CFR part 60 for 

Fourier Transform Infrared (FTIR) 

CEMS for procedures to certify and 

conduct ongoing quality assurance on 

these FTIR CEMS. In addition, we 

expect to publish a PS specific to HCl 

CEMS in the near future (prior to the 

compliance date of this rule). In the 

meantime, you may petition the 

Administrator under the procedure 

given in 40 CFR 63.7(f) for an alternative 

approach to compliance monitoring or 

testing for HCl or any other regulated 

pollutant. 

When using a sorbent trap monitoring 

system, you may use each pair of 

sorbent traps to collect Hg samples for 

no more than 15 boiler operating days. 

Under the general duty to monitor at all 

times, you must replace traps in a 

timely manner to ensure that Hg 

emissions are sampled continuously. 

For Hg monitoring, the EPA is adding 

Hg monitoring provisions as Appendix 

A to 40 CFR part 63, subpart UUUUU, 

and requiring use of these provisions to 

document continuous compliance with 

the rule for coal-fired, IGCC, and solid 

oil derived-fired units that cannot 

qualify as LEEs. Appendix A 

consolidates all Hg monitoring 

provisions. 

Today’s rule provides two basic Hg 

continuous monitoring options: Hg 

CEMS and sorbent trap monitoring 

systems. Appendix A requires initial 

certification and periodic quality 

assurance (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 NISTtraceable elemental Hg standards; a 3- 

level system integrity check (similar to 

a linearity check), using NIST-traceable 

oxidized Hg standards; a cycle time test; 

and a relative accuracy test audit 

(RATA). Table A–1 of Appendix A 

summarizes the performance 

specifications for the required 

certification tests. For ongoing QA of the 

Hg CEMS, Appendix A requires daily 

calibrations, weekly single-point system 

integrity checks, quarterly linearity 

checks (or 3-level system integrity 

checks), and annual RATAs. Table A–2 

in Appendix A summarizes these 

ongoing QA test requirements and the 

applicable performance criteria for Hg 

CEMS, which are consistent with those 

published in support of CAMR and are, 

thus, familiar to the industry. 

For sorbent trap monitoring systems, 

a RATA is required for initial 

certification, and annual RATAs are 

required for ongoing QA. The 

performance specification for these 

RATAs is the same as for the RATAs of 

the Hg CEMS. Bias adjustment of the 

measured Hg concentration data is not 

required. For day-to-day operation of 

the sorbent trap system, Appendix A 

requires you to follow the procedures 

and QA/QC criteria in PS 12B in 

Appendix B to 40 CFR part 60. PS 12B 

is nearly identical to the Appendix K to 

40 CFR part 75, published in support of 

CAMR and with which the industry is 

familiar. The 40 CFR part 75 concepts 

of: 

a. Determining the due dates for 

certain QA tests on the basis of ‘‘QA 

operating quarters’’ and 

b. Grace periods for certain QA tests 

apply to both Hg CEMS and sorbent trap 

monitoring systems. Mercury 

concentrations measured by Hg CEMS 

or sorbent trap systems are used 

together with hourly flow rate, diluent 

gas, moisture, and electrical load data, 

to express the Hg emissions in units of 

the rule, on an hourly basis (i.e., lb/TBtu 

or lb/GWh). Section 6 of Appendix A 

provides the necessary equations for 

these unit conversions. 

For HCl and HF CEMS, the EPA is 

adding monitoring provisions as 

Appendix B to 40 CFR part 63, Subpart 

UUUUU. Appendix A references 

performance specification (PS) 15 of 

Appendix B to 40 CFR part 60 for 

Fourier Transform Infrared (FTIR) 

CEMS for procedures to certify and 

conduct ongoing quality assurance on 

these FTIR CEMS. In addition, we 

expect to promulgate a generic PS 

specific to HCl CEMS prior to the 

compliance date of this rule. In the 

meantime, you may petition the 

Administrator under the procedure 

given in 40 CFR 63.7(f) for an alternative 

approach to compliance monitoring or 

testing for HCl or any other regulated 

pollutant. 

(2) Use of stack tests. If you 

demonstrate initial compliance on the 

basis of a stack test, you must 

demonstrate continuous compliance by 

conducting periodic stack tests on a 

quarterly basis. This includes filterable 

PM (or non-mercury HAP metals) and 

HCl from coal-fired and solid oilderived fuel-fired EGUs, and filterable 

PM (or HAP metals) and HCl and HF 

from liquid oil-fired EGUs with the 

following exceptions: 

a. If you use a PM CPMS and 

associated operating limit, you may 

conduct the applicable Method 5 or 

Method 29 test once annually rather 

than quarterly, in which case you must 

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 a 

requirement for you to develop and 

follow a site-specific monitoring plan to 

be approved by the delegated authority. 

You must demonstrate compliance with 

the operating limit by using all valid 

hourly data collected during each 

successive 30-boiler operating day 

period rolled daily. The 30-boiler 

operating day rolling average is 

calculated by all of the valid hourly 

average PM CPMS output values 

collected for the 30 boiler operating 

days (excluding hours of startup and 

shutdown; see section V.E. of this 

preamble). 

b. If you combust liquid fuels and if 

your fuel moisture content is no greater 

than 1.0 percent, you may demonstrate 

ongoing compliance with HCl and HF 

emissions limits by: 

i. Measuring fuel moisture content of 

each shipment of fuel if your fuel 

arrives on a batch basis; 

ii. Measuring fuel moisture content 

daily if your fuel arrives on a 

continuous basis; or 

iii. Obtaining and maintaining a fuel 

moisture certification from your fuel 

supplier. 

Should the moisture in your liquid 

fuel be more than 1.0 percent, you must 

i. Conduct HCl and HF emissions 

testing quarterly and establish sitespecific monitoring to demonstrate 

continued acid gas control performance 

between periodic tests, or 

ii. Use an HCl CEMS and/or HF 

CEMS. 

c. If your existing unit qualifies as an 

LEE for Hg, you must conduct another 

30-day Method 30B performance test on 

your unit once per year to reestablish 

that the unit continues to qualify as a 

LEE for Hg. If the results of the LEE test 

show that the unit exceeds 10 percent 

of the emissions limit or exceeds the 

potential to emit 29 pounds of Hg per 

year, you will lose LEE status for the 

unit. You can regain LEE status for that 

unit if every required performance test 

for a 3-year period shows that emissions 

from the unit did not exceed the LEE 

limit. If LEE status is lost for a solid fuel 

unit, you must commence quarterly 

performance testing until you install, 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9373 

309WebFIRE is the Internet version of FIRE. The 

Factor Information Retrieval (FIRE) Data System is 

a database management system containing EPA’s 

recommended emission estimation factors for 

criteria and HAP. It includes information about 

industries and their emitting processes, the 

chemicals emitted, and the emission factors 

themselves. 

certify, and operate a Hg CEMS or a 

sorbent trap monitoring system, and you 

must complete the installation and 

certification within 6 months of losing 

LEE status; for a liquid fuel unit, you 

must commence quarterly performance 

testing. 

d. If a liquid oil-fired EGU has an 

annual capacity factor on oil of less than 

8 percent of its maximum or nameplate 

heat input, whichever is greater, you 

must demonstrate continuous 

compliance with the applicable work 

practice standard by conducting at least 

once every 36 calendar months (48 

calendar months if a neural network is 

employed) a combustion process tuneup, a thorough equipment inspection, 

and an optimization to minimize 

generation of CO and NOX, all meeting 

the requirements of this final rule. You 

must maintain and inspect the burners 

and associated combustion controls, 

tuning the specific burner type to 

optimize combustion, obtaining and 

recording CO and NOX values before 

and after burner adjustments, keeping 

records of activity and measurements, 

and submitting a report for each tuneup conducted. You must collect CO and 

NOX data using portable analyzers 

(which typically include handheld or 

similar devices). Specific details are 

addressed in 40 CFR 63.10021 of the 

final rule. 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 non-mercury 

pollutant to once every 36 months. If 

any subsequent emissions test for that 

pollutant exhibits emissions greater 

than 50 percent of the emissions limit, 

you must revert to the original 

emissions testing frequency until you 

re-establish a 3-year period of very low 

emissions no greater than 50 percent of 

the standard. 

f. For liquid oil-fired units that 

demonstrate continuous compliance 

with quarterly performance tests for HCl 

and HF emission limits rather than 

through use of HCl and HF CEMS, the 

final rule requires a site-specific 

monitoring plan in addition to the 

quarterly tests. For these pollutants, 

there is unlikely to be any existing 

underlying monitoring (such as 

compliance assurance monitoring) that 

serves as an additional tool to ensure 

the source’s operations remain 

consistent with operating conditions 

during a recent successful performance 

test. The requirement for a site-specific 

monitoring plan fills this gap and 

ensures that in between tests, the source 

continues to operate in a manner 

designed to maintain HCl and HF 

emissions in compliance with the 

emission limits under this rule. The 

appropriate parameters to monitor will 

depend on the compliance strategy 

employed by a specific source, and thus 

EPA is enabling the monitoring 

approach to be established on a case-bycase basis. Given the relatively small 

number of these units and the other 

compliance options available, we 

anticipate that this approach will apply 

to a small set of units. The monitoring 

plan will identify the parameters 

monitored, the monitoring methods, the 

QA/QC elements that apply, and the 

data reduction elements (including 

appropriate averaging periods, as 

applicable). See 40 CFR 

63.10000(c)(2)(ii). 

(3) Work practice standard. For the 

performance tune-up work practice 

requirements, you must demonstrate 

continuous compliance by conducting 

the work practice at least once every 36 

calendar months (48 calendar months if 

a neural network is employed). The 

work practice involves maintaining and 

inspecting the burners and associated 

combustion controls, tuning the specific 

burner type, as applicable, to optimize 

combustion, obtaining and recording CO 

and NOX values before and after burner 

adjustments, keeping records of activity 

and measurements, and submitting a 

report for each tune-up conducted. A 

combustion tune-up will involve 

optimizing combustion of the unit 

consistent with manufacturer’s 

instruction as applicable, or in 

accordance with best combustion 

engineering practice for that burner 

type. 

H. What are the notification, 

recordkeeping and reporting 

requirements? 

All new and existing sources in all 

subcategories must comply with certain 

requirements of the General Provisions 

(40 CFR part 63, subpart A), which are 

identified in Table 9 of this final rule. 

The General Provisions include specific 

requirements for notifications, 

recordkeeping, and reporting. You must 

submit a notification of compliance 

status report for each unit, according to 

the schedule required by 40 CFR 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 63.10(e)(3) of subpart A, that 

indicate whether a deviation from any 

of the requirements in the rule occurred 

and whether or not any process changes 

occurred and compliance certifications 

were reevaluated. As discussed below, 

we are finalizing a requirement to use 

the 40 CFR part 75-based Emissions 

Collection and Monitoring Plan System 

(ECMPS) for reporting emissions and 

related data for units using CEMS for 

most pollutants. Also, as discussed 

below, for the PM CPMS, PM CEMS, 

and performance test results, we require 

you to use EPA’s WebFIRE 309 database 

for reporting. 

This rule requires you to keep certain 

records to demonstrate compliance with 

each emission limit and work practice 

standard. The General Provisions to 40 

CFR part 63 specify these recordkeeping 

requirements (see Table 9 to this 

subpart). Among other specific records, 

you must keep the following: 

(1) All reports and notifications 

submitted to comply with this rule. 

(2) Continuous monitoring data as 

required in this rule. 

(3) Each instance in which you did 

not meet an emission limit, work 

practice requirement, operating limit, or 

other compliance obligation (i.e., 

deviations from this rule). 

(4) Daily hours of operation by each 

unit. 

(5) As part of the general duty to keep 

all monitoring data, fuel moisture 

content of liquid fuel, if you elect to 

demonstrate compliance using that 

information. 

(6) A copy of the results of all 

performance tests, monitor 

certifications, performance evaluations, 

or other compliance demonstrations 

conducted to demonstrate initial or 

continuous compliance with this rule. 

(7) A copy of your site-specific 

performance evaluation test plans 

developed for this rule as specified in 

40 CFR 63.8(e), if applicable. 

(8) A copy of your acid gas control 

system parameter monitoring plan 

under 40 CFR 63.10000(c)(2)(ii). 

You also must submit the following 

additional notifications: 

(1) Notifications required by the 

General Provisions. 

(2) Initial Notification no later than 

120 calendar days after you become 

subject to this subpart. 


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(3) Notification of Intent to conduct 

performance tests and/or compliance 

demonstration at least 60 calendar days 

before the performance test and/or 

compliance demonstration is scheduled. 

(4) Notification of Compliance Status 

60 calendar days following completion 

of the performance test and/or 

compliance demonstration. 

Electronic reporting is becoming a 

common element of modern life (as 

evidenced by electronic banking and 

income tax filing), and the EPA is 

beginning to require electronic 

submittal of environmental data. 

Electronic reporting is already common 

in environmental data collection and 

many media offices at EPA are reducing 

reporting burden for the regulated 

community by embracing electronic 

reporting systems as an alternative to 

paper-based reporting. 

One of the major benefits of reporting 

electronically is standardization, to the 

extent possible, of the data reporting 

formats that provides more certainty to 

users of what data are required in 

specific reports. For example, electronic 

reporting software allows for more 

efficient data submittal and the 

software’s validation mechanism helps 

industry users submit fewer incomplete 

reports. This alone saves industry report 

processing resources and reduces 

transaction times. Standardization also 

allows for development of efficient 

methods to compile and store much of 

the documentation required to be 

reported by this rule. 

Use of Electronic Reporting System 

We are requiring that you submit 

certain reports electronically. In 

addition to supporting regulation 

development, control strategy 

development, and other air pollution 

control activities, having an electronic 

database populated with these reports 

will save industry, state, local, tribal 

agencies, the public, and the EPA 

significant time, money, and effort 

while also improving the transparency 

and quality of emission inventories and, 

as a result, air quality regulations. 

The reports to be submitted 

electronically include all performance 

test reports, notification of compliance 

status reports, compliance, and 

continuous monitoring data summaries 

specified in 40 CFR 63.10031 of this 

rule. Performance tests are required to 

be conducted as described in 40 CFR 

63.7 of the General Provisions. The data 

that must be submitted as the 

performance test report are also 

described in 40 CFR 63.7. These data 

must be submitted (except in limited 

cases) to EPA’s WebFIRE database by 

using the electronic reporting tool (ERT) 

and the Compliance and Emissions Data 

Reporting Interface (CEDRI) that is 

accessed through EPA’s Central Data 

Exchange (CDX), as described below. 

The data requirements for the 

notification of compliance status and 

compliance reports are described in 

detail in the regulatory text (40 CFR 

63.10031) of this rule, but they 

essentially mirror the requirements in 

40 CFR 63.6 of the General Provisions. 

These reports will also be submitted to 

WebFIRE using an electronic form 

found in CEDRI and through the CDX as 

described below. As required in 40 CFR 

63.10031(f)(2) of the final rule, the 

continuous monitoring summaries are 

required to be submitted quarterly. The 

quarterly reports must include all of the 

calculated 30-boiler operating day 

rolling average values derived from the 

PM CPMS. These reports will also be 

submitted to WebFIRE using an 

electronic form found in CEDRI and 

through the CDX, as described below. 

This same approach will apply if a 

source elects to use a PM CEMS or 

receives approval to use a HAP metals 

CEMS as an alternative monitoring 

method. 

The availability of electronic 

reporting for sources subject to the 

Subpart UUUUU will provide 

efficiency, improved services, better 

accessibility of information, and more 

transparency and accountability. 

Additionally, submittal of these 

required reports electronically provides 

significant benefits for regulatory 

agencies, industry, and the public. The 

compliance data electronic reporting 

system (CEDRI and CDX) is being 

developed such that once a facility’s 

initial data entry into the system is 

established and a report is generated, 

subsequent data submittal will only 

consist of electronic updates to existing 

information in the system. Such a 

system will effectively reduce the 

burden associated with submittal of data 

and reports by reducing the time, costs, 

and effort required to submit and update 

hard copies of documentation. State, 

local, and tribal air pollution control 

agencies will also benefit from having 

access to the more streamlined and 

accurate electronic data submitted to the 

EPA. Electronic reporting will allow for 

an electronic review process rather than 

a manual data assessment, making 

review and evaluation of the sourceprovided data and calculations easier 

and more efficient. Electronic reporting 

will also benefit the public by 

generating a more transparent review 

process and increasing the ease and 

efficiency of data accessibility. 

Furthermore, electronic reporting will 

reduce the burden on the regulated 

community by reducing the effort 

involved in data collection and 

reporting activities. In the future, we 

anticipate there will be fewer and less 

substantial data collection requests in 

conjunction with prospective required 

residual risk assessments or technology 

reviews. Electronic reporting will 

substantially reduce this burden, 

because the EPA will already have these 

data available and consolidated in an 

electronic database named WebFIRE. 

We anticipate that using electronic 

reporting for the required reports will 

result in an overall reduction in 

reporting costs; for a discussion of the 

economic and cost impacts of electronic 

reporting, see section XII.D. of this 

preamble. 

Another benefit of electronic data 

submittal is that these data will greatly 

improve the overall quality of existing 

and new emissions factors by 

supplementing the pool of emissions 

test data for establishing emissions 

factors and by ensuring that the factors 

are more representative of current 

industry operational procedures. A 

common complaint heard from industry 

and regulators is that emission factors 

are outdated or not representative of a 

particular source category. With timely 

receipt and incorporation of data from 

most performance tests, the EPA will be 

able to ensure that emission factors, 

when updated, represent the most 

current range of operational practices. 

Data entry of these electronic reports 

will be through the CEDRI that is 

accessed through EPA’s CDX 

(www.epa.gov/cdx). Data submitted 

electronically through CEDRI will be 

stored in CDX as an official copy of 

record. 

Once you have accessed CEDRI, you 

will select the applicable subpart for the 

report that you are submitting. You will 

then select the report being submitted, 

enter the data into the form, and click 

on the submit button. In some cases, 

such as with submittal of a notification 

of compliance status report, you will 

select the report icon, enter basic facility 

information, and then upload the report 

in a specified file format. 

In addition, we believe that there will 

be value in allowing other reporting 

forms to be developed and used in cases 

where the other reporting forms can 

provide an alternate electronic file 

consistent with EPA’s form output 

format. This approach has been used 

successfully to provide alternatives for 

other electronic forms (e.g., income tax 

submittal). 

In cases where performance test data 

are to be submitted to the EPA, you 

must enter the performance test data 


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and information into the electronic 

reporting tool (ERT) which can be 

accessed at http://www.epa.gov/ttn/ 

chief/ert/index.html. In CEDRI, the user 

must then upload the ERT file. CEDRI 

submits a copy of the ERT project data 

file directly to WebFIRE where the data 

are made available. Where performance 

test reports are submitted, WebFIRE 

notifies the appropriate state, local, or 

tribal agency contact that an ERT project 

data file was received from the source. 

Submitting performance test data 

electronically to the EPA will apply 

only to those performance tests 

conducted using test methods that will 

be supported by the ERT. The ERT 

contains a specific electronic data entry 

form for most of the commonly used 

EPA reference methods. A listing of the 

pollutants and test methods supported 

by the ERT is available at the ERT Web 

site listed above. 

I. Submission of Emissions Test Results 

to the EPA 

The EPA has determined that 

harmonization of the monitoring and 

reporting requirements of this final rule 

with 40 CFR part 75 is appropriate, 

where the affected industry already has 

a well-defined system for continuous 

monitoring and reporting of emissions 

under that part. Therefore, the Agency 

is finalizing monitoring and reporting 

requirements for most CEMS that are 

consistent with 40 CFR part 75. You 

must report CEMS data (other than PM 

CEMS data or data from alternative 

monitoring subject to site-specific 

approval such as a HAP metals CEMS) 

to the EPA electronically, on a quarterly 

basis, using the ECMPS. 

The ECMPS process divides 

electronic data into three categories, the 

first of which is monitoring plan data. 

You must maintain the electronic 

monitoring plan separately and can 

update it at any time if necessary. The 

monitoring plan documents the 

characteristics of the affected units (e.g., 

unit type, rated heat input capacity, etc.) 

and the monitoring methodology used 

for each parameter (e.g., CEMS). The 

monitoring plan also describes the type 

of monitoring equipment used 

(hardware and software components), 

includes analyzer span and range 

settings, and provides other useful 

information. Nearly all coal-fired EGUs 

are subject to the ARP and thus have 

established electronic monitoring plans 

that describe their required SO2, flow 

rate, CO2 or O2, and, in some cases, 

moisture monitoring systems. The EPA 

will adjust the ECMPS monitoring plan 

format to accommodate this same type 

of information for Hg, HCl, and HF 

CEMS, with the addition of a few codes 

for the new parameters. 

The second type of data collected 

through ECMPS is certification and QA 

test data. These data include data from 

linearity checks, RATAs, cycle time 

tests, 7-day calibration error tests, and a 

number of other QA tests that are 

required to validate the emissions data. 

You may submit the results of these 

tests to the EPA as soon as you obtain 

the results, with one notable exception. 

Daily calibration error tests are not 

treated as individual QA tests, due to 

the large number of records generated 

each quarter. Rather, these tests must be 

included in the quarterly electronic 

reports, along with the hourly emissions 

data. The ECMPS system is set up to 

receive and process certification and QA 

data from SO2, CO2, O2, flow rate, and 

moisture monitoring systems that are 

installed, certified, maintained, 

operated, and quality-assured according 

to 40 CFR part 75. EGUs routinely 

submit these data to the EPA under the 

ARP and other emissions trading 

programs. 

To accommodate the certification and 

QA tests for Hg CEMS, other CEMS, and 

sorbent trap monitoring systems, the 

structure and functionality of ECMPS 

needs relatively few changes, because 

most of the tests are the same as those 

required for other gas monitors. For 

reporting Hg, HCl, SO2, and HF CEMS 

data under this rule, we are disabling 

ECMPS’ 40 CFR part 75 bias test (which 

is required for certain types of monitors 

under the EPA’s SO2 and NOX

emissions trading programs). The bias 

adjustment of the data from these 

monitors is unnecessary for compliance 

with the rule. 

The third type of data collected 

through ECMPS is the hourly emissions 

data, which, as previously noted, is 

reported on a quarterly schedule. You 

must submit reports within 30 days after 

the end of each calendar quarter. The 

emissions data format requires hourly 

reporting of all measured and calculated 

emissions values, in a standardized 

electronic format. You must report 

direct measurements made with CEMS, 

such as gas concentrations, in a Monitor 

Hourly Value (MHV) record. A typical 

MHV record for gas concentration 

includes data fields for: 

(1) The parameter monitored (e.g., 

SO2); 

(2) The unadjusted and bias-adjusted 

hourly concentration values (note that if 

bias adjustment is not required, only the 

unadjusted hourly value is reported); 

(3) The source of the data, i.e., a code 

indicating either that each reported 

hourly concentration is a quality 

assured value from a primary or backup 

monitor, or that quality-assured data 

were not obtained for the hour; and 

(4) The percent monitor availability 

(PMA), which is updated hour-by-hour. 

This generic record structure could 

easily accommodate hourly average 

measurements from CEMS used under 

this rule. 

The ECMPS reporting structure is 

quite flexible, which makes it useful for 

assessing compliance with various 

emission limits. The Derived Hourly 

Value (DHV) record allows calculations 

of a wide variety of quantities from the 

reported hourly emissions data. For 

instance, if an emission limit is 

expressed in units of lb/MMBtu, the 

DHV record can be used to report hourly 

pollutant concentration values in these 

units of measure, since the lb/MMBtu 

values can be derived from the hourly 

pollutant and diluent gas (CO2 or O2) 

concentrations reported in the MHV 

records. The ECMPS can also 

accommodate multiple DHV records for 

a given hour in which more than one 

derived value is required to be reported. 

The system will support reporting 

hourly data in the units of the emission 

standards (e.g., lb/MMBtu, lb/TBtu, lb/ 

GWh, etc.) when hourly Hg 

concentration data are reported through 

ECMPS using the DHV record, in 

conjunction with the appropriate 

equations and auxiliary information 

such as heat input and electrical load 

(all of which are reported hourly in the 

emissions reports). 

One change in this rule from standard 

40 CFR part 75 emissions data reporting 

is elimination of the requirement to 

provide substitute data calculations 

within ECMPS. The ARP and other 

emissions trading programs that report 

emissions data to the EPA using 40 CFR 

part 75 require provision of a complete 

data record. Emissions data are required 

to be reported for every unit operating 

hour. When CEMS are out of service, 

substitute data must be reported to fill 

in the gaps. However, for the purposes 

of compliance with a NESHAP, 

reporting substitute data during monitor 

outages is not necessary, as 

quantification of total mass emissions is 

not the focus of the rule. Hours when a 

monitoring system is out of service 

would be counted as hours of monitor 

down-time and may be a deviation from 

the monitoring requirements of this rule 

unless the rule provides an exception, 

as it does for routine quality control and 

maintenance activities. 

In contrast to the CEMS-related data 

that would be submitted through 

ECMPS, you must submit reports of 

performance tests and PM CPMS data to 

EPA’s WebFIRE database by using 

CEDRI that is accessed through EPA’s 


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CDX (www.epa.gov/cdx). You must 

submit performance test data in the file 

format generated through use of EPA’s 

ERT (see http://www.epa.gov/ttn/chief/ 

ert/index.html) within 60 days of 

performance test completion. Electronic 

data submittal requirements are 

described in section V.H. of this 

preamble. 

Other notifications and reports not 

currently accepted by the electronic 

reporting system will be submitted in 

hardcopy form at this time. 

VI. Summary of Significant Changes 

Since Proposal 

The previous section described the 

requirements that EPA is finalizing in 

this rule. This section will discuss in 

greater detail the key changes EPA is 

making from the proposed. These 

changes result from EPA’s review of the 

additional data and information 

provided to us and our consideration of 

the many substantive and thoughtful 

comments submitted on the proposal. 

While our approach and methodology to 

establishing the standards remain the 

same, the changes make the final rule 

more flexible and cost-effective, reduce 

reliability concerns and improve clarity, 

while fully preserving, or improving, 

the public health and environmental 

protection required by the CAA. 

A. Applicability 

Since proposal, the EPA has made 

certain changes to the applicability 

provisions of the final rule to provide 

clarity. These changes do not change the 

universe of sources subject to the rule. 

The EPA is revising a number of the 

proposed definitions 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 oilfired 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 onethird of its potential electric output capacity 

and more than 25 MWe output to any utility 

power distribution system for sale is 

considered an electric utility steam 

generating unit. 

40 CFR 63.10042. 

We also indicated how we would 

determine whether units were coal-fired 

or oil-fired fired EGUs: ‘‘If an EGU burns 

coal (either as a primary fuel or as a 

supplementary fuel), or any 

combination of coal with another fuel 

(except solid waste as noted below), the 

unit is considered to be coal fired under 

this proposed rule. If a unit is not a coalfired 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 previous 3 

calendar years or for more than 15.0 

percent of the annual heat input during 

any one of those calendar years. 76 FR 

25025. We further stated that for a unit 

to be ‘‘capable of combusting’’ coal or 

oil the unit must have a permit that 

authorized the combustion of coal or oil 

and also have the appropriate fuel 

handling facilities on-site. Id. 

As explained in the proposed rule, 

natural gas-fired EGUs were not 

included in the December 2000 listing 

so such units that otherwise met the 

CAA section 112(a)(8) definition of EGU 

because of natural gas combustion are 

not subject to the final 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, oil-fired, or IGCC 

EGUs if they burned 10 percent or less 

of coal, oil, or synthetic gas derived 

from coal or solid oil over 3 years or 15 

percent or less of such fuels in any one 

year. We did not intend to suggest that 

to be considered a fossil fuel-fired EGU 

a natural gas-fired unit that is not a coalfired 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 coalor 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 calendar years or less 

than 15.0 percent of the annual heat input 

during any one of those calendar years) is not 

considered to be a fossil fuel-fired EGU under 

this proposed rule. The EPA has based its 

threshold value on the definition of ‘‘oilfired’’ 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 fuelfired and for which fossil fuel the unit 

is fossil fuel-fired. We intended to 

include a unit combusting more than 

the defined amount of coal in one of the 

coal-fired EGU subcategories. If a unit is 

not coal-fired and it is combusting more 

than the defined amount of oil, we 

intended to include the unit in one of 

the oil-fired EGU subcategories. We also 

intended to make clear that EGUs that 

are neither coal-fired nor oil-fired but 

combust more than the defined amount 

of natural gas are natural gas-fired EGUs 

not subject to the final standards. 

However, the definitions, as proposed, 

were not sufficiently descriptive. 

For example, we included a definition 

for ‘‘coal-fired electric utility steam 

generating unit’’ that did not include the 

requirement that the unit must combust 

coal for at least 10 percent of the heat 

input over 3 years or 15 percent of the 

heat input in any one year. Instead, in 

the proposed rule we indicated that a 

unit was coal-fired if it burned coal in 

any amount. We did not intend to 


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310Although 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. 

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 oilfired 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 

coal-fired EGU because it would meet 

the definition of ‘‘fossil fuel-fired’’ and 

be burning some coal, even though that 

level of coal combustion alone would 

not be sufficient to make the unit ‘‘fossil 

fuel-fired’’ for coal. That result is at 

odds with our intent. The same would 

hold true for an EGU that combusts 

mostly natural gas and less than 10 

percent synthetic gas derived from coal 

over a 3-year period. Our proposal 

preamble makes clear that we did not 

intend this result because we 

specifically stated that units burning 90 

percent or more natural gas over a 3- 

year period would be considered 

natural-gas fired EGUs. 76 FR 25025. 

In addition, we proposed to define 

‘‘[u]nit designed to burn solid oil fuel 

subcategory’’ to include any EGU that 

burned a solid fuel derived from oil for 

more than 10.0 percent of the average 

annual heat input during the previous 3 

calendar years or for more than 15.0 

percent of the annual heat input during 

any one of those calendar years, either 

alone or in combination 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 ‘‘coalfired’’ EGU. Therefore, there would be 

some confusion for a source that 

blended coal with solid oil derived fuel 

(e.g., petroleum coke). For example, the 

owner or operator of an EGU that 

burned sufficient solid oil-derived fuel 

that accounted for 80 percent of the heat 

input in a given year and the remainder 

of the fuel was coal would not be sure 

which standard applied because the 

definitions in the proposed rule were 

internally inconsistent. 

For these reasons, we are revising the 

definitions for ‘‘coal-fired electric utility 

steam generating unit,’’ ‘‘integrated 

gasification combined cycle electric 

utility steam generating unit,’’ and ‘‘oilfired electric utility steam generating 

unit,’’ and we are adding a definition of 

‘‘natural-gas fired electric utility steam 

generating unit’’ as set out in 40 CFR 

63.10042. 

In addition to these changes, we are 

revising the definition of ‘‘fossil fuelfired’’ based on comments. We are 

revising the definition to remove the 

heat input equivalent of 25 MW because 

commenters noted that the equivalency 

used (taken from 40 CFR part 60, 

subpart Da) could not be applied 

consistently because of differing boiler 

efficiencies. Commenters noted that 

owners/operators were familiar with the 

use of the ‘‘MW’’ term for the boilers 

and boilers include nameplate 

capacities that are readily identifiable. 

We are also including a revision to the 

definition so that the fossil fuel 

combustion thresholds of 10 percent 

over 3 consecutive years and 15 percent 

in one year are evaluated after the 

applicable compliance date of the final 

rule on a rolling basis. Commenters 

correctly noted that some existing coaland oil-fired EGUs will convert their 

units to alternative fuels (e.g., natural 

gas or biomass) and if the definition 

were finalized as proposed such units 

could be improperly subjected to the 

final standards. 

The new definition is set out in 40 

CFR 63.10042. 

For clarity, we are also removing the 

definition of ‘‘[u]nit designed to burn 

liquid oil fuel subcategory,’’ revising the 

definition of ‘‘[u]nit designed to burn 

solid oil fuel subcategory,’’ adding 

definitions for the continental and noncontinental liquid oil-fired EGU 

subcategories, and adding a definition of 

a limited-use liquid oil-fired EGU as set 

out in 40 CFR 63.10042. 

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 MW). In the 

preamble to the proposed rule, we 

indicated that a unit subject to one of 

the Boiler NESHAP that increases its 

electricity output and meets the 

definition of an EGU would be subject 

to the EGU NESHAP for the 6-month 

period after the unit meets the EGU 

definition.310 76 FR 25026. Assuming 

the EGU did not meet the definition of 

an EGU following that initial 

occurrence, at the end of the 6-month 

period it would revert back to being 

subject to the Boiler NESHAP, or other 

applicable standard. We solicited 

comment on the extent to which 

situations like this might occur, how the 

EPA should address situations where 

units change applicability, and whether 

we should include provisions similar to 

those included in the final CISWI (40 

CFR 60.2145) to address such situations. 

Id. 

Several commenters asked the Agency 

to include provisions in the final rule 

that would address situations like the 

ones described in the preamble to the 

proposed rule. Because applicability to 

the final rule is based in part on the 

statutory definition of an EGU is CAA 

section 112(a)(8), similar to the situation 

with units combusting solid waste 

under CAA section 129(g)(1) (e.g., 

CISWI Rule), we are adopting provisions 

in the final rule that are based on the 

fuel switching provisions of the final 

CISWI Rule (See Final CISWI Rule, 40 

CFR 60.2145). For example, a 

cogeneration unit that did not 

historically provide more than one third 

of its potential electrical output capacity 

to a power distribution system could 

change its output and provide more 

than 25 megawatts electrical output to 

any power distribution system for sale. 

Such units would be subject to MATS. 

If the cogeneration unit later reduced its 

output such that it no longer met the 

definition of an EGU, that source would 

nevertheless remain subject to MATS 

for at least 6 months from the date that 

the unit first qualified as an EGU. 

In addition, we are finalizing a 

provision whereby you may opt to 

remain subject to the provisions of this 

final rule, unless you combust solid 

waste, in which case you are a solid 

waste incineration unit subject to 

standards under CAA section 129 (e.g., 

40 CFR part 60, subpart CCCC (New 

Source Performance Standards (NSPS) 

for Commercial and Industrial Solid 

Waste Incineration Units), or subpart 

DDDD (Emissions Guidelines (EG) for 

Existing Commercial and Industrial 

Solid Waste Incineration Units)). We 

believe the provision to opt to remain 

subject to this final rule will ameliorate 

conditions where EGUs may potentially 

move between NESHAP on a relatively 

frequent basis. Notwithstanding the 

provisions of this final rule, an EGU that 

starts combusting solid waste is subject 

to standards under CAA section 129, 

and the unit remains subject to those 

standards until the unit no longer meets 

the definition of a solid waste 

incineration unit consistent with the 

provisions of the applicable CAA 

section 129 standards. 


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9378 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

311 It is our understanding that no unit combusts 

coal-refuse from nonagglomerating virgin coal 

having a calorific value (moist, mineral matter-free 

basis) of less than 19,305 kJ/kg (8,300 Btu/lb). 

The changes to the definitions 

described above provide clarity to 

sources, permitting agencies, and the 

public about the applicability of the rule 

and help ensure that sources are 

appropriately covered by the regulation. 

B. Subcategories 

In this final rule, the EPA is adding 

subcategories for limited-use oil-fired 

units and non-continental oil-fired units 

and revising the definitions for the coalfired EGU subcategories. 

The proposed rule subcategorized 

EGUs burning coal into two 

subcategories: EGUs designed for coal 

≥8,300 Btu/lb and EGUs designed for 

virgin coal <8,300 Btu/lb (low rank 

virgin coal). We received a number of 

comments indicating that the definition 

of the low rank virgin coal subcategory 

was technically deficient. 

Under CAA section 112(d)(1), the 

Administrator has the discretion to 

‘‘* * * distinguish among classes, 

types, and sizes of sources within a 

category or subcategory in establishing 

* * *’’ standards. The EPA maintains 

that, normally, any basis for 

subcategorization (i.e., class, type, or 

size) must be related to an effect on HAP 

emissions that is due to the difference 

in class, type, or size of the units. See 

76 FR 25036–25037. The EPA believes 

it is not reasonable to exercise our 

discretion without such a difference 

because if sources can achieve the same 

level of emissions reductions 

notwithstanding a difference in class, 

type, or size, the purposes of CAA 

section 112 are better served by 

requiring a similar level of control for 

all such units in the category or 

subcategory. See Lignite Energy Council 

v. EPA, 198 F. 3d 930, 933 (D.C. Cir. 

1999) (‘‘EPA is not required by law to 

subcategorize—section 111[b][2] merely 

states that ‘the Administrator may 

distinguish among classes, types, and 

sizes within categories of new sources’’’ 

(emphasis original)); see also CAA 

section 112(d)(1) (containing almost 

identical language to CAA section 111, 

CAA section 112(d)(1) provides that 

‘‘the Administrator may distinguish 

among classes, types, and sizes of 

sources within a category or subcategory 

in establishing [ ] standards * * *’’). 

Even if we determine that emissions 

characteristics are different for units 

that differ in class, type, or size, the 

Agency may still decline to 

subcategorize if there are compelling 

policy justifications that suggest 

subcategorization is not appropriate. Id. 

When developing the proposed rule, 

we examined the EGUs in the top 

performing 12 percent of sources for Hg 

emissions. We determined that: 

There were no EGUs designed to burn a 

nonagglomerating virgin coal having a 

calorific value (moist, mineral matter-free 

basis) of 19,305 kJ/kg (8,300 Btu/lb) or less 

in an EGU with a height-to-depth ratio of 

3.82 or greater among the top performing 12 

percent of sources for Hg emissions, 

indicating a difference in the emissions for 

this HAP from these types of units. The 

boiler of a coal-fired EGU designed to burn 

coal with that heat value is bigger than a 

boiler designed to burn coals with higher 

heat values to account for the larger volume 

of coal that must be combusted to generate 

the desired level of electricity. Because the 

emissions of Hg are different between these 

two subcategories, we are proposing to 

establish different Hg emission limits for the 

two coal-fired subcategories. For all other 

HAP from these two subcategories of coalfired units, the data did not show any 

difference in the level of the HAP emissions 

and, therefore, we have determined that it is 

not reasonable to establish separate 

emissions limits for the other HAP. 76 FR 

25036–67. 

Based on this determination, we 

proposed to establish two subcategories 

with separate Hg limits. Comments on 

the proposed rule indicate that we 

correctly identified the EGUs that 

should be included in each subcategory, 

but the comments also demonstrated 

that we made certain incorrect 

conclusions that require us to revise the 

definitions of our coal-fired EGU 

subcategories. The revised definitions 

ensure that the EGUs we identified at 

proposal as having different Hg 

emissions remain in one subcategory. 

As stated above, we believed at 

proposal that the boiler size was the 

cause of the different Hg emissions 

characteristics that led us to propose 

subcategorization, but many 

commenters indicated that it was not 

the boiler size but the fact that the EGUs 

burned a nonagglomerating virgin coal 

having a calorific value (moist, mineral 

matter-free basis) of less than 19,305 kJ/ 

kg (8,300 Btu/lb) (low rank virgin coal) 

that causes the disparity in Hg 

emissions. Several commenters 

indicated that their EGUs were designed 

to burn and burned low rank virgin coal 

but the units did not meet the height-todepth ratio that EPA proposed. For 

example, the height-to-depth ratio of 

certain EGUs in this subcategory is in 

fact 3.5, not 3.82. Further, there are 

other EGUs in this subcategory that are 

circulating fluidized bed (CFB) 

combustion units which do not meet the 

height-to-depth ratio parameters in the 

proposed rule, nor are they anything 

like the pulverized coal (PC) EGUs we 

initially identified as having the 3.82 

height-to-depth ratio. 

In addition to the comments 

concerning EGUs firing this coal, we 

received comments from at least two 

commenters indicating that the EPA 

should clarify in which subcategory a 

unit belongs when it does not burn low 

rank virgin coal but is designed to 

combust low rank virgin coal and has a 

height-to-depth ratio of greater than 

3.82. Commenters also indicated that 

CFB units that are burning coalrefuse 311 or other nonagglomerating 

virgin coal having a calorific value 

(moist, mineral matter-free basis) of 

19,305 kJ/kg (8,300 Btu/lb) or greater are 

‘‘designed to burn’’ any type of coal. 

Owners of CFB units that are not firing 

low rank virgin coal asked which 

subcategory they belong to based on 

their ability to burn any type of coal 

(including low rank virgin coal) without 

modification. These commenters also 

indicated that some coal refuse that is 

combusted has a heating value less than 

8,300 Btu/lb but is not ‘‘virgin coal.’’ It 

was unclear to which subcategory they 

belonged since the proposed rule did 

not in fact require the unit to burn any 

specific coal, instead only requiring the 

unit be ‘‘designed’’ to burn lower Btu 

coal. 

Based on the comments received, we 

reevaluated the subcategory definitions 

because we were concerned that the 

definitions we proposed would 

improperly categorize a number of the 

EGUs in both subcategories. We 

concluded that we should not maintain 

the proposed definition for ‘‘[u]nits 

designed for coal <8,300 Btu/lb’’ and 

exclude the CFB units and PC EGUs 

with a height-to-depth ratio less than 

3.82 that combusted low rank virgin 

coal. 

We were equally concerned that the 

subcategory definitions not be revised in 

a manner that would move EGUs that 

we believed the data show could 

comply with a more stringent standard 

into a subcategory with a less stringent 

standard because, aside from the type of 

EGUs we identified, all other classes, 

types, and sizes of EGUs were 

represented among the top performing 

12 percent for Hg in the ≥8,300 Btu/lb 

subcategory. We were particularly 

concerned about the CFB units because 

other CFB units are well represented 

among the best performing EGUs for Hg 

in the ≥8,300 Btu/lb subcategory, but the 

CFB units burning low rank virgin coal 

are not achieving the same levels of Hg 

emissions control. Including the best 

performing CFB units from the other 

subcategory in the low rank virgin coal 

subcategory would likely lead to a Hg 

standard as stringent as the standard for 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9379 

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 reasons, we 

did not revise the definition to include 

CFB units and PC EGUs with a heightto-depth ratio greater than 3.5. 

After fully considering the available 

information, including the comments 

received, we have concluded that it is 

appropriate to continue to base the 

subcategory definitions, at least in part, 

on whether the EGUs were designed to 

burn and, in fact, did burn low rankvirgin coal, but that it is not appropriate 

to continue to use the height-to-depth 

ratio criteria because that approach 

would potentially exclude EGUs we 

identified as having different Hg 

emission characteristics and include 

EGUs that did not have different 

emissions characteristics. We recognize 

that some commenters have taken the 

position that it is unlawful to 

subcategorize based on factors such as 

fuel type but nothing in the statute 

prohibits such an approach and the case 

law supports this approach to the extent 

courts have considered 

subcategorization based on such factors. 

See Sierra Club v. Costle, 657 F. 2d 298, 

318–19 (D.C. Cir. 1981) (differing 

pollutant content of input material can 

justify a different standard based on 

subcategorization authority to 

‘‘distinguish among classes, types and 

sizes within categories of new sources’’). 

Furthermore, we believe had Congress 

intended to prohibit the EPA from 

subcategorizing based on an EGU being 

designed to use and using a certain 

material input (e.g., fuel) it would have 

clearly stated such intent in the CAA. 

However, we believe the Agency could 

decline to exercise its discretion to 

subcategorize even if the potential result 

would be the prohibition of the use of 

some materials if the circumstances 

warranted. We note that even if we did 

not subcategorize on the final basis 

selected, the Hg emissions standard of 

1.2E0 lb/Tbtu for the ‘‘unit designed for 

coal ≥8,300 Btu/lb’’ would remain the 

same. 

We considered basing the subcategory 

solely on an EGU being designed to 

burn and burning low rank virgin coal. 

We decided not to do so because we 

were concerned that such a definition 

would allow sources to potentially meet 

the definition by combusting very small 

amounts of low rank virgin coal. For 

example, an EGU on the east coast (or 

any other region) that was not designed 

to burn and did not routinely burn low 

rank virgin coal could import one truck 

full of low rank virgin coal and burn a 

very small quantity of it periodically to 

meet the subcategory definition. To 

avoid creating this potential loophole, 

we considered other characteristics that 

would distinguish EGUs combusting 

low rank virgin coal. 

We determined that these EGUs are 

universally constructed ‘‘at or near’’ a 

mine containing low rank virgin coal 

because it is not cost-effective to 

transport large quantities of such fuel 

long distances. Furthermore, we believe 

that this subcategory of EGUs are almost 

always built at a mine and limited 

transportation of the coal is only 

required as the mine face moves over 

the course of time. Many such EGUs 

construct dedicated rail lines, private 

roads, or conveyor systems to transport 

the coal to the EGU as the mine face 

moves. We obtained information from 

data acquired to develop the CSAPR 

indicating that the longest distance any 

EGU firing low rank virgin coal 

transports that coal is 40 miles. We 

believe that this distance is near the 

outer limits for the transport of such 

coal, but, even for those EGUs, the EGUs 

were constructed closer to a now idle 

mine or closer to the working face of a 

mine that has now expanded away from 

the EGU site. For these reasons, we are 

including a requirement that the unit be 

constructed and operated at or near a 

mine containing the low rank virgin 

coal it burns. 

We are revising the coal-fired EGU 

subcategory definitions as set out in 40 

CFR 63.10042. 

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 being required to 

comply only with the less stringent Hg 

emission standard. 

As discussed in response to 

comments, we do not believe that 

additional subcategorization of other 

coal-fired EGUs is reasonable or 

appropriate. All other coal-fired EGUs 

that are not designed to burn and are 

burning low rank virgin coal are 

represented among the best performing 

sources for Hg, such that no argument 

exists to support that the Hg emissions 

from those EGUs are different. In any 

case, even if emissions are somewhat 

different as some commenters suggest, 

we would decline to exercise our 

discretion because the data demonstrate 

that the best performing EGUs designed 

to burn and burning all other ranks of 

coal are able to achieve the MACT level 

of control using currently available 

controls and other HAP emission 

reduction mechanisms (e.g., coal 

washing) for the ≥8,300 Btu/lb 

subcategory. 

A second issue related to 

subcategorization concerns noncontinental liquid oil-fired EGUs. At 

proposal, the EPA did not have 

sufficient emissions data from noncontinental liquid oil-fired EGUs upon 

which to base a subcategory and took 

comment on the issue. The data have 

since been provided in response to the 

ICR and we received comments 

suggesting that a non-continental 

subcategory is appropriate based on the 

location of such units, the limited 

availability of alternative fuel sources, 

and the fact that the emissions 

characteristics of such units are distinct 

from continental liquid oil-fired EGUs. 

The EPA has evaluated the data and 

comments and we agree that a 

subcategory is warranted based for the 

reasons suggested by the commenters. 

Therefore, the Agency is finalizing the 

liquid oil-fired EGU subcategories of 

‘‘continental’’ and ‘‘non-continental.’’ 

Lastly, the EPA did not have 

sufficient information on limited-use 

liquid oil-fired EGUs upon which to 

base a subcategory at proposal because 

some sources required to test under the 

ICR did not submit the data until after 

proposal. We took comment on whether 

a limited-use subcategory was 

warranted. Commenters indicated that 

their units were a different class and 

type of units because many of them 

were only called to service to address 

reliability issues associated with, for 

example, natural gas curtailments. The 

commenters further indicated that their 

units are different because of the 

generally infrequent use and the 

sporadic, and at times frequent, start-up 

and shutdown periods (e.g., they are 

often only required to run for a couple 

of hours). These factors would lead to 

differences in the emissions 

characteristics for these units such that 

a numeric standard based on base load 

units would not likely be achievable 

during the very limited times that these 

limited use oil-fired units operate. 

Based on comments received and our 

own analysis, we are finalizing a 

subcategory for limited-use liquid oilfired EGUs as discussed further 

elsewhere in this preamble. 


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9380 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

C. Emission Limits 

The proposed rule included 

numerical emission limits for PM, Hg, 

HCl, HF, SO2, total HAP metals, and 

individual HAP metals, depending on 

the subcategory and specific situation. 

These proposed limits resulted from 

calculations of MACT floors using 

information and data available to the 

Agency prior to proposal, as required by 

CAA section 112. Based on information 

and data received during the comment 

period, we have made data and 

calculation corrections where necessary 

and then re-ranked the best performing 

units in the MACT floor pools. Based on 

the new ranking, a limited number of 

the emission limits in the final rule have 

changed from those proposed. 

In addition to adjustments to the 

emission limits themselves, we are 

finalizing several other changes to the 

emission standards that will simplify 

and improve compliance for sources 

without compromising the toxics 

reductions achieved. One key change, as 

discussed elsewhere in this notice, is 

that we have changed the surrogate for 

non-mercury metallic HAP from total 

particulate matter (PM) to filterable PM 

for coal-fired and solid oil-derived 

EGUs. This change is based on 

information provided in comments and 

our own conclusion that measurement 

of filterable PM provided assurance of 

equivalent HAP emissions control. Most 

of the non-mercury metal HAP, for 

which PM is a surrogate, are filterable 

PM and the one that is not (Se) is well 

controlled by the limit on acid gases. 

Using filterable PM as the surrogate will 

allow us to use continuous PM 

monitoring systems, which measure 

filterable (but not total) PM, thereby 

providing a more continuous measure of 

compliance. 

For liquid oil-fired EGUs, based on 

comments received and corrections 

made to the data submitted, we have 

added a filterable PM limit in the final 

rule as an alternative equivalent 

standard for the total metal-HAP limit in 

the proposed rule. In addition, as 

discussed elsewhere in this notice, we 

have added measurement of the 

moisture content of the oil (with a 1 

percent limit) as an alternate 

compliance assurance measure for 

liquid oil-fired EGUs for determining 

compliance with the HCl and HF limits. 

Direct measurement of HCl and HF 

remains a compliance demonstration 

method in the final rule. Finally, as 

discussed in section VI.D of this notice, 

the final work practice standard 

consisting of burner tune-ups, much like 

those required for organic HAP control, 

for those limited-use liquid oil-fired 

EGUs whose annual capacity factor is 

less than 8 percent. 

D. Work Practice Standards for Organic 

HAP Emissions 

As noted earlier in section V.D., the 

final rule includes a work practice 

standard for organic HAP, including 

dioxins and furans, applicable to all 

EGUs. As noted in section V.D. above, 

the majority of emissions of these 

pollutants are below the detection levels 

of EPA test methods and, therefore, are 

impractical to measure. The work 

practice standard, described below, is a 

practical approach to ensuring that 

equipment is maintained and run so as 

to minimize emissions of dioxins and 

furans, and we expect it to be more 

effective than establishing a numeric 

standard that cannot reliably be 

measured or monitored. The work 

practice also applies to the limited-use 

liquid oil-fired subcategory included in 

the final rule. 

The work practice involves 

maintaining and inspecting the burners 

and associated combustion controls (as 

applicable), tuning the specific burner 

type to optimize combustion, obtaining 

and recording CO and NOX values 

before and after the burner adjustments, 

keeping records of activity and 

measurements, and submitting a report 

for each tune-up conducted. In Table 3 

of the final regulation, we have clarified 

that this refers to performance tune-ups, 

not tests, and have addressed the 

frequency requirement as discussed in 

response to comments about the 

appropriateness of the 18-month 

frequency. The provisions of 40 CFR 

63.10006(h)(i) refer to 40 CFR 

63.10021(e) for the specific steps 

required to be part of the periodic tuneup. We have also adjusted the language 

in the final rule to recognize the value 

of automated boiler optimization tools 

such as neural network systems. 

Under the final rule, the tune-up must 

be conducted at each planned major 

outage and in no event less frequently 

than every 36 calendar months, with an 

exception that if the unit employs a 

neural-network system for combustion 

optimization during hours of normal 

unit operation, the required frequency is 

a minimum of once every 4 years (48 

calendar months). Initial compliance 

with the work practice standard of 

maintaining burners must occur within 

180 days of the compliance date of the 

rule. The initial compliance 

demonstration for the work practice 

standard of conducting a tune-up may 

occur prior to the compliance date of 

the rule, but must occur no later than 42 

months (36 months plus 180 days) from 

the compliance date of the rule or, in 

the case of units employing neural 

network combustion controls, 54 

months (48 months plus 180 days). If 

the tune-up occurs prior to the 

compliance date of the rule, you must 

maintain adequate records to show that 

the tune-up met the requirements of this 

standard. 

We have made a number of specific 

changes to address what to do for 

repairs that may require longer term 

corrective actions, additional methods 

for evaluating combustion effectiveness, 

and clarification on procedures for 

recording CO and NOX information. 

There were specific comments that 

opposed the reference to manufacturer 

specifications, if available. We retained 

this language in the final rule, but note 

that these specifications apply only to 

the extent applicable. Specifically, if 

manufacturer specifications only 

address equipment or conditions that 

are no longer present given current 

boiler operations, then those 

specifications are not applicable and 

other combustion engineering best 

practice procedures for that burner type 

would apply. We have also clarified that 

portable emission monitoring 

equipment may be used to collect the 

required emissions optimization data 

regarding pre- and post-tune-up CO and 

NOX emission levels. 

E. Requirements During Startup, 

Shutdown, and Malfunction 

We proposed numerical emission 

standards that would apply at all times, 

including during periods of startup, 

shutdown, and malfunction. Although 

at proposal we stated that we were not 

setting a different standard for startup 

and shutdown, we did propose different 

standards for startup and shutdown by 

our inclusion of the default values 

described below, which applied only 

during startup and shutdown. 

Specifically, we stated: 

To appropriately determine emissions 

during startup and shutdown and account for 

those emissions in assessing compliance with 

the proposed emission standards, we propose 

use of a default diluent value of 10.0 percent 

O2 or the corresponding fuel specific CO2

concentration for calculating emissions in 

units of lb/MMBtu or lb/TBtu during startup 

or shutdown periods. For calculating 

emissions in units of lb/MWh or lb/GWh, we 

propose source owners use an electrical 

production rate of 5 percent of rated capacity 

during periods of startup or shutdown. We 

recognize that there are other approaches for 

determining emissions during periods of 

startup and shutdown, and we request 

comment on those approaches. We further 

solicit comment on the proposed approach 

described above and whether the values we 

are proposing are appropriate. 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9381 

312 In response to the ICR, we also received SO2

CEMS data and the Agency had additional SO2

CEMS data available through the CAMD ARP 

database. We are not able to identify specific 

periods of start-up and shutdown in either the ICR 

CEMS data or the CAMD ARP data, and the ICR 

respondents do not indicate that the ICR data 

includes periods of startup and shutdown. We set 

the emission limits for SO2 and HCl using the data 

provided to the EPA from the 2010 ICR, not the 

CAMD data, since those data were taken 

concurrently under the same specified operating 

conditions using the same fuel. We used the SO2

CEMS data that was submitted in response to the 

ICR by converting it to single point data to correlate 

to the data from units that did not provide CEMS 

data from the relevant testing period. The emissions 

limits for the NESHAP incorporated variability by 

applying the 99 percent UPL to the average 

emissions developed from the stack test data and 

SO2 CEMS data that was converted to stack test 

data. Thus, we did not have data on which to 

establish an SO2 standard during periods of startup 

and shutdown and the numeric standards do not 

apply to those periods in the final rule. In contrast, 

the NSPS for SO2 is applicable during periods of 

startup and shutdown since the long term CAMD 

ARP CEMS data were used to determine the average 

performance of the best demonstrated technology. 

Those long term data were assumed to incorporate 

process variability including that associated with 

fuel and process/operational changes and periods of 

startup and shutdown. 

We proposed application of the 

respective emission limits during 

periods of startup and shutdown and 

use of default values to calculate the 

emission limits. The standards that 

apply at all times other than startup and 

shutdown are production-based limits, 

which is why we proposed the default 

values. The default values were meant 

to account for the fact that during 

startup and shutdown events, 

production (in this case the generation 

of electricity) is by definition 

nonexistent. Thus, in effect, we 

proposed a separate standard to apply 

during startup and shutdown. 

We received a variety of comments on 

the proposed standards that would 

apply during startup and shutdown. 

Many commenters pointed to the lack of 

data in the record concerning emissions 

that occur during periods of startup and 

shutdown. They further asserted that 

emissions during these periods can be 

highly variable in light of the sequence 

of events that occurs during the startup 

and shutdown of an EGU. Although a 

number of commenters supported the 

use of the diluent factor approach, 

including the default 5 percent of rated 

capacity, during startup/shutdown 

periods, other commenters questioned 

the feasibility of collecting additional 

data during such periods and had 

concerns regarding the reliability of 

measurements obtained from EGUs 

during such periods. 

In response to the Agency’s ICR to the 

utility industry, seven owners or 

operators indicated that they provided 

startup and shutdown data for their 

EGUs. These data were submitted in 

response to the requirement in the ICR 

to provide all available data from the 5 

years prior to the date the ICR was 

issued. Of these data, there were almost 

no HAP data for startup and shutdown 

periods and almost all of the data failed 

to meet our data quality 

requirements.312 Thus, we do not have 

sufficient data on emissions that occur 

during startup and shutdown on which 

to set emission standards. We are 

therefore establishing work practice 

standards rather than numeric 

emissions standards for periods of 

startup and shutdown in the final rule. 

Before we describe those work practices, 

we first address what constitutes startup 

and shutdown. 

Several commenters had an expansive 

view of what constitutes startup and 

shutdown. We disagree with these 

commenters that asserted that periods of 

‘‘load swings’’ should be considered 

‘‘startup’’ or ‘‘shutdown,’’ as they are 

generally routine, normal operations 

with production (i.e., generation of 

electricity) taking place. We maintain 

that the standards as promulgated 

account for any variability in emissions 

that may occur during these periods 

over a 30-day averaging period, and 

commenters have provided no data that 

cause us to doubt that determination. 

We have included definitions of startup 

and shutdown in the final rule that are 

consistent with the definitions in the 

proposed rule. At proposal, we defined 

startup as the setting in operation of an 

affected source or portion of an affected 

source for any purpose, and shutdown 

as the cessation of operation of an 

affected source or portion of an affected 

source for any purpose. 

Commenters sought more clarity 

regarding the meaning of these terms as 

applied to EGUs, so we are revising the 

definitions in the final rule as set out in 

40 CFR 63.10042. 

These interpretations are tailored for 

EGUs and are consistent with the 

definitions of ‘‘startup’’ and 

‘‘shutdown’’ contained in the 40 CFR 

part 63, subpart A General Provisions. 

We believe these revised definitions 

address the comments and are rational 

based on the fact that EGUs function to 

provide electricity primarily for sale to 

the grid but also at times for use on-site; 

therefore, EGUs should be considered to 

be operating normally at all times 

electricity is generated. We further 

believe these revised definitions address 

what some commenters describe as 

‘‘warm’’ and ‘‘hot’’ startups as long as 

the EGU is shutdown (i.e., no fuel fired 

and no electricity generation) prior to 

the ‘‘warm’’ or ‘‘hot’’ startup period. 

As for the work practices, in this final 

rule, the EPA is requiring sources to 

operate using either natural gas or 

distillate oil for ignition during startup. 

The EPA also is requiring sources to 

vent emissions to the main stack(s) and 

operate all control devices necessary to 

meet the normal operating standards 

under this final rule (with the exception 

of dry scrubbers and SCRs) when coal, 

solid oil-derived fuel, or residual oil is 

fired in the boiler during startup or 

shutdown. It is the responsibility of the 

operators of EGUs to start their dry 

scrubber and SCR systems appropriately 

to comply with relevant standards 

applicable during normal operation. 

The EPA carefully considered fuels 

and potential operational constraints of 

air pollution control devices (APCDs) 

when designing its work practices for 

periods of startup and shutdown. The 

EPA notes that there is no technical 

barrier to burning natural gas or 

distillate oil for longer portions of 

startup or shutdown periods, if needed, 

at a boiler, and the HAP emission 

reduction benefits warrant additional 

utilization of such fuels until the 

temperature and stack emissions 

pressure is sufficient to engage the 

APCDs. The EPA is aware that SCR 

systems with ammonia injection need to 

be operated within a prescribed and 

relatively narrow temperature window 

to provide NOX reductions. Further, the 

EPA is aware that dry scrubbers also 

need to be operated close to flue gas 

saturation temperature. Because these 

devices have specific temperature 

requirements for proper operation, the 

EPA notes in its work practices that it 

is the responsibility of the operators of 

EGUs to start their SCR and dry 

scrubber systems appropriately to 

comply with relevant standards 

applicable during normal operation. 

Some commenters have asserted that 

firing of fuel oil during periods of 

startup and shutdown constrains 

operation of PM controls (ESPs and 

baghouses) because under cooler 

conditions, acids and tars can condense 

on surfaces in these controls. The 

commenters assert that such 

condensation can cause detrimental 

impacts on hardware and operation of 

these controls, and could cause safety 

concerns. The EPA understands that 

concerns with acidic and tarry deposits 

are related to firing of heavy (residual) 

oil and not distillate oil. Accordingly, 

with residual fuel oil firing, site-specific 

flue gas temperature and oxygen (O2) 

concentration thresholds may be 

applicable to minimize condensation of 

acids and tars and thereby minimize any 

potential for detrimental impacts on 

hardware and any safety concerns. 


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313Coal Power, May 1, 2007: http:// 

www.coalpowermag.com/plant_design/Coal-PlantO-and-M-River-Locks-and-Barges-Are-an-AgingWorkforce-Too 36.html. 

314Neundorfer: Lesson #r, p.4–7, Table 4–1: 

http://www.neundorfer.com/FileUploads/CMSFiles/ 

Fabric%20Filter%2OMaterial [0].pdf. 

However, the EPA notes that its work 

practice requirements provide flexibility 

to the operator to take appropriate sitespecific remedial measures, if needed. 

The EPA further notes that boilers have 

several options to prevent detrimental 

impacts by: (1) Using startup fuels, 

natural gas or distillate oil, until 

appropriate flue gas conditions have 

been reached and then fire residual oil; 

(2) pre-coating the PM control 

surfaces 313 with an alkaline powder 

(e.g., limestone); (3) installing 

chemically resistant bags 314 in 

baghouses if applicable; and (4) using 

low-sulfur oils. The EPA also notes that 

currently the industry has many 

operational residual oil-fired boilers that 

are started up with either natural gas or 

distillate fuel oil. At these boilers, the 

transition from the startup fuel, 

distillate oil or natural gas, to residual 

oil is already being practiced without 

unacceptable impacts on APCDs 

including PM controls, which are 

operated to meet applicable opacity 

limits. Based on this experience and the 

options described above, those boilers 

where residual oil is used for either a 

part of the startup period, or as the main 

fuel, will also be able to operate their 

PM controls to meet the work practice 

requirements of the rule. Note that coal 

firing is done at high enough 

temperatures that concerns with 

condensation are not relevant. None of 

the commenters have specifically 

commented on this aspect of coal firing. 

The EPA is not aware of any 

operational constraints applicable to 

operation of wet scrubbers during 

startup that could cause detrimental 

impacts on wet scrubber hardware and 

safety concerns and none of the 

commenters have commented on this 

aspect of wet scrubber operation. 

Finally, the EPA notes that dry 

sorbent injection (DSI) can be applied 

across a very broad temperature range 

and will be engaged when residual oil 

or coal is fired in a boiler to comply 

with HCl requirements. Again, no 

comments have been received on this 

aspect of DSI operation. 

This final rule requires work practice 

standards for emissions during startup 

and shutdown, and the rule requires 

sources to measure and report their 

emissions at all times, including periods 

of startup and shutdown, when 

continuous monitoring is used to 

demonstrate compliance. Data collected 

under this final rule will provide the 

EPA with information to more fully 

analyze this issue and address it during 

the 8-year review established under 

CAA section 112. 

We now address malfunctions. In 

contrast to the exclusion of startup and 

shutdown period emissions from 30- 

boiler operating day rolling average 

emissions, the final rule requires 

inclusion of emissions during periods of 

source or APCD malfunction. We have 

concluded that when combined with the 

availability of an affirmative defense as 

described below, this is an appropriate 

and practical approach. 

As mentioned earlier, periods of 

startup, normal operations, and 

shutdown are all predictable and 

routine aspects of a source’s operations. 

However, by contrast, malfunction is 

defined as a ‘‘sudden, infrequent, and 

not reasonably preventable failure of air 

pollution control and monitoring 

equipment, process equipment or a 

process to operate in a normal or usual 

manner * * *’’ (40 CFR 63.2). The EPA 

has determined that CAA section 112 

does not require that emissions that 

occur during periods of malfunction be 

factored into development of CAA 

section 112 standards. Under CAA 

section 112, emissions standards for 

new sources must be no less stringent 

than the level ‘‘achieved’’ by the best 

controlled similar source and for 

existing sources generally must be no 

less stringent than the average emission 

limitation ‘‘achieved’’ by the best 

performing 12 percent of sources in the 

category. There is nothing in CAA 

section 112 that directs the Agency to 

consider malfunctions in determining 

the level ‘‘achieved’’ by the best 

performing or best controlled sources 

when setting emission standards. 

Moreover, while the EPA accounts for 

variability in setting emissions 

standards consistent with the CAA 

section 112 case law, nothing in that 

case law requires the Agency to 

consider malfunctions as part of that 

analysis. Clean Air Act section 112 uses 

the concept of ‘‘best controlled’’ and 

‘‘best performing’’ unit in defining the 

level of stringency that CAA section 112 

performance standards must meet. 

Applying the concept of ‘‘best 

controlled’’ or ‘‘best performing’’ to a 

unit that is malfunctioning presents 

significant difficulties, as malfunctions 

are sudden and unexpected events. 

Further, accounting for malfunctions 

would be difficult, if not impossible, 

given the myriad different types of 

malfunctions that can occur across all 

sources in the category and given the 

difficulties associated with predicting or 

accounting for the frequency, degree, 

and duration of various malfunctions 

that might occur. As such, the 

performance of units that are 

malfunctioning is not ‘‘reasonably’’ 

foreseeable. See, e.g., Sierra Club v. 

EPA, 167 F. 3d 658, 662 (D.C. Cir. 1999) 

(The EPA typically has wide latitude in 

determining the extent of data-gathering 

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 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 nonmalfunctioning source. The EPA’s 

approach to malfunctions is consistent 

with CAA section 112, and we believe 

it is a reasonable interpretation of the 

statute. This approach to malfunctions 

has been used consistently in CAA 

section 112 and CAA section 129 

rulemaking actions since the D.C. 

Circuit’s decision in Sierra Club v. EPA, 

551 F.3d 1019 (D.C. Cir. 2008) vacated 

the SSM exemption contained in CFR 

63.6(f)(1) and 40 CFR 63.6(h)(1). (See, 

e.g., National Emission Standards for 

Hazardous Air Pollutants From the 

Portland Cement Manufacturing 

Industry and Standards of Performance 

for Portland Cement Plants, 75 FR 54970 

(September 9, 2010); Standards of 

Performance for New Stationary Sources 

and Emission Guidelines for Existing 

Sources: Sewage Sludge Incineration 

Units; Final Rule, 76 FR 15372 (March 

21, 2011). 

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 


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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 63.2 (definition of 

malfunction). 

Finally, the EPA recognizes that even 

equipment that is properly designed and 

maintained can sometimes fail and that 

such failure can sometimes cause an 

exceedance of the relevant emission 

standard. (See, e.g., State 

Implementation Plans: Policy Regarding 

Excessive Emissions During 

Malfunctions, Startup, and Shutdown 

(Sept. 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions (Feb. 

15, 1983)). The EPA is therefore adding 

to the final rule an affirmative defense 

to civil penalties for exceedances of 

emission limits that are caused by 

malfunctions. See 40 CFR 63.10042 

(defining ‘‘affirmative defense’’ to mean, 

in the context of an enforcement 

proceeding, a response or defense put 

forward by a defendant, regarding 

which the defendant has the burden of 

proof, and the merits of which are 

independently and objectively 

evaluated in a judicial or administrative 

proceeding). We also have added other 

regulatory provisions to specify the 

elements that are necessary to establish 

this affirmative defense; the source must 

prove by a preponderance of the 

evidence that it has met all of the 

elements set forth in 63.10001. (See 40 

CFR 22.24). The criteria ensure that the 

affirmative defense is available only 

where the event that causes an 

exceedance of the emission limit meets 

the narrow definition of malfunction in 

40 CFR 63.2 (i.e., sudden, infrequent, 

not reasonable preventable and not 

caused by poor maintenance and or 

careless operation). For example, to 

assert the affirmative defense 

successfully, the source must prove by 

a preponderance of the evidence that 

excess emissions ‘‘[w]ere caused by a 

sudden, infrequent, and unavoidable 

failure of air pollution control and 

monitoring equipment, process 

equipment, or a process to operate in a 

normal or usual manner * * *’’ The 

criteria also are designed to ensure that 

steps are taken to correct the 

malfunction, to minimize emissions in 

accordance with section 63.10001 and 

to prevent future malfunctions. For 

example, the source must prove by a 

preponderance of the 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 22.27). 

The EPA is including an affirmative 

defense in the final rule as we have in 

other recent MACT rules so as to 

balance the tension, inherent in many 

types of air regulation, to ensure 

adequate compliance while 

simultaneously recognizing that despite 

the most diligent of efforts, emission 

limits may be exceeded under 

circumstances beyond the control of the 

source. The EPA must establish 

emission standards that ‘‘limit the 

quantity, rate, or concentration of 

emissions of air pollutants on a 

continuous basis.’’ 42 U.S.C. 7602(k) 

(defining ‘‘emission limitation and 

emission standard’’). See generally 

Sierra Club v. EPA, 551 F.3d 1019, 1021 

(D.C. Cir. 2008). Thus, the EPA is 

required to ensure that section 112 

emissions limitations are continuous. 

The affirmative defense for malfunction 

events meets this requirement by 

ensuring that even where there is a 

malfunction, the emission limitation is 

still enforceable through injunctive 

relief. While ‘‘continuous’’ limitations, 

on the one hand, are required, there is 

also case law indicating that in some 

situations it is appropriate for the EPA 

to account for the practical realities of 

technology. For example, in Essex 

Chemical v. Ruckelshaus, 486 F.2d 427, 

433 (D.C. Cir. 1973), the D.C. Circuit 

acknowledged that in setting standards 

under CAA section 111 ‘‘variant 

provisions’’ such as provisions allowing 

for upsets during startup, shutdown and 

equipment malfunction ‘‘appear 

necessary to preserve the reasonableness 

of the standards as a whole and that the 

record does not support the ‘never to be 

exceeded’ standard currently in force.’’ 

See also, Portland Cement Association 

v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973). Though intervening case law 

such as Sierra Club v. EPA and the CAA 

1977 amendments calls into question 

the relevance of these cases today, they 

support the EPA’s view that a system 

that incorporates some level of 

flexibility is reasonable. The affirmative 

defense simply provides for a defense to 

civil penalties for excess emissions that 

are proven to be beyond the control of 

the source. By incorporating an 

affirmative defense, the EPA has 

formalized its approach to upset events. 

In a Clean Water Act setting, the Ninth 

Circuit required this type of formalized 

approach when regulating ‘‘upsets 

beyond the control of the permit 

holder.’’ Marathon Oil Co. v. EPA, 564 

F.2d 1253, 1272–73 (9th Cir. 1977). But 

see, Weyerhaeuser Co. v. Costle, 590 

F.2d 1011, 1057–58 (D.C. Cir. 1978) 

(holding that an informal approach is 

adequate). The affirmative defense 

provisions give the EPA the flexibility to 

ensure both that its emission limitations 

are ‘‘continuous’’ as required by 42 

U.S.C. 7602(k), and account for 

unplanned upsets and thus support the 

reasonableness of the standard as a 

whole. 

F. Testing and Initial Compliance 

We have carefully evaluated the wideranging comments on testing, 

continuous monitoring, and other 

provisions regarding initial compliance 

demonstrations, and we have made 

adjustments intended to help streamline 

implementation while still ensuring 

adequate demonstration of compliance 

with the emission limits and other 

standards established under this final 

rule. The significant changes include: 

1. No Fuel Analysis Requirements 

Apart from an alternative that allows 

you to analyze fuel moisture for liquid 

oil-fired EGUs rather than measuring 

HCl and HF, the final rule does not 

include any of the fuel analysis 

requirements that were in the proposed 

rule, either as part of initial compliance 

demonstrations or ongoing compliance 

demonstrations. In reviewing the results 

of the fuel analyses and the expected 

range of results that would be received 

from laboratories conducting the 

proposed analyses, we determined that 

too many results would be returned as 

‘‘below detection level’’ and, thus, 

provide little information to assist with 

rule implementation and compliance 

oversight. Given the costs and efforts 

involved, we determined that the 

proposed fuel analysis requirements 

would not be an effective compliance 

monitoring tool for this final rule. 

2. Clarification of Testing 

We have clarified that where options 

for emission limits apply (such as 

filterable PM versus non-mercury HAP 

metals, or SO2 versus HCl), you need 

only perform stack testing to 

demonstrate compliance with the 

selected emission limit. For example, if 

you elect to meet the individual nonVerDate Mar<15>2010 22:15 Feb 15, 2012 Jkt 226001 PO 00000 Frm 00081 Fmt 4701 Sfmt 4700 E:\FR\FM\16FER2.SGM 16FER2

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9384 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

mercury HAP metals standards, you 

must conduct the Method 29 test for the 

metals, and you do not have to conduct 

a Method 5 test for PM. 

3. Low Emitting EGU Qualification 

We have significantly modified the 

proposed requirements to qualify as a 

LEE unit for a pollutant other than Hg 

based on an initial performance test. 

Under the proposed rule, the operating 

limit monitoring provided additional 

assurance of compliance for a source 

qualified for non-mercury LEE status 

based on an initial compliance 

demonstration. Under the final rule, to 

qualify for LEE status for pollutants 

other than Hg, a unit must meet the LEE 

criteria for a series of performance tests 

over a 3-year period to demonstrate that 

the unit continues to perform well 

below the standard for which the source 

has obtained LEE status. 

G. Continuous Compliance 

The most significant changes to the 

testing and monitoring requirements 

involve the procedures for 

demonstrating continuous compliance. 

The proposed rule contained different 

options involving CEMS, periodic stack 

tests, fuel analysis, and various PM and 

control device operating limits. The 

final rule greatly simplifies the 

requirements and provides two basic 

approaches for most situations: use of 

continuous monitoring (either CEMS or 

PM continuous parametric monitoring 

system, CPMS) or periodic quarterly 

testing. The final rule does not contain 

the proposed fuel analysis requirements. 

For periodic testing, the proposed rule 

required testing every month or every 2 

months. For those EGU owners or 

operators who choose to use emissions 

testing to demonstrate compliance, the 

final rule requires quarterly filterable 

PM or non-mercury metals HAP, 

whether individual or total metals, 

testing for coal- and liquid oil-fired 

units. The rule requires quarterly HCl 

testing for coal-fired units and quarterly 

HCl and HF testing, along with sitespecific monitoring for liquid oil-fired 

units to ensure compliance with the HCl 

and HF standards. The final rule also 

has a separate compliance 

demonstration for those liquid oil-fired 

EGUs that have an annual capacity 

factor of less than 8 percent (emission 

limits do not apply, just the tune-up 

work practice standard). For those EGU 

owners or operators who choose to use 

emissions testing to demonstrate 

compliance, the final rule requires 

quarterly filterable PM or non-mercury 

metals HAP, whether individual or total 

metals, testing for coal- and liquid oilfired units; quarterly HCl testing for 

coal-fired units and quarterly HCl and 

HF testing, along with site-specific 

parameter monitoring for liquid oil-fired 

units to ensure compliance with the HCl 

and HF standards. 

The continuous monitoring options 

remain generally intact from the 

proposed rule, with relatively minor 

clarifications concerning calculation of 

30-boiler operating day averages and QA 

requirements. 

The final rule eliminates all operating 

limits for PM except for the use of a PM 

CPMS. For the PM CPMS, the final rule 

clarifies procedures for setting this 

operating limit and how it is distinct 

from the PM emission limit. The PM 

CPMS will not be correlated as a PM 

CEMS under PS 11 and will produce 

data in terms of a signal you define. 

That signal could be milliamps, stack 

concentration, or other output signal 

instead of PM emissions in units of the 

standard. The operating limit will be set 

using the highest hourly average 

obtained from the PM CPMS during the 

performance test. Compliance with the 

limit is based on a 30-boiler operating 

day rolling average basis. However, the 

final rule also does provide for the use 

of a PM CEMS to determine compliance 

with the filterable PM emission limit if 

the source elects to use this approach. 

The EPA believes that some sources 

may be interested in adopting this direct 

approach, and so has included that 

option in the final rule. If this approach 

is selected, the PM CEMS is used as the 

direct method of compliance and no 

additional testing is required other than 

tests that are required as part of the QA 

requirements in PS 11 and Procedure 2. 

To use this option, the source must elect 

to meet the filterable PM standard, and 

not one of the HAP metals standards. 

Apart from the operating limit for sitespecific monitoring associated with 

liquid oil-fired EGUs, we removed the 

other operating limits for control 

devices based on a review of the 

comments, after considering other 

programs in place to ensure proper 

operations of controls at EGUs. Those 

other programs include compliance 

assurance monitoring under part 64, 

part 70, and New Source Review permit 

conditions, and other SIP and NSPS 

requirements for operating and 

maintaining equipment in accordance 

with good air pollution control 

practices. Those requirements, in 

combination with the CEMS, PM CPMS, 

and frequent periodic testing provisions 

under the final rule, will enhance the 

monitoring of continuous compliance 

with the requirements of this rule. 

Because the EPA is concerned that 

there will be little or no monitoring in 

these underlying applicable 

requirements for acid gases at liquid oilfired EGUs, the final rule requires a sitespecific monitoring plan for those units 

in this subcategory that demonstrate 

compliance with the HCl and HF 

standards through quarterly 

performance tests. With the exception 

for limited-use liquid oil-fired EGUs and 

other monitoring options available (such 

as fuel moisture monitoring or HCl/HF 

CEMS), the EPA believes this provision 

will apply to few units. The owner or 

operator will submit the site-specific 

plan to identify appropriate parameters 

that ensure that the operations of the 

unit critical to meeting the HCl/HF 

emission limits remain consistent with 

conditions during performance testing. 

This will be approved similarly to an 

alternative monitoring request. The plan 

should include the parameters, 

monitoring approach, QA/QC elements, 

and data reduction (including averaging 

period) elements. Like the PM CPMS 

operating limit, the operating limit for 

acid gas control devices on liquid oilfired EGUs will be set using the highest 

hourly average obtained during the HCl 

and HF performance tests. Compliance 

with the limit is based on a 30-boiler 

operating day rolling average basis. 

Finally, we have changed the 

continuous compliance requirements for 

the performance tune-up work practice 

standard since the proposal. Our intent 

was that this work practice standard 

could be performed in conjunction with 

routine maintenance operations at a 

facility and be a logical extension of 

routine best practices for boiler 

inspection and optimization. Based on 

the comments received, we have 

reduced the required frequency for this 

inspection to every 3 years and 

provided incentives for neural network 

combustion management and 

optimization practices by providing a 

longer interval of 4 years between 

inspections when such systems are in 

use at a given EGU. 

H. Emissions Averaging 

We are finalizing that owners and 

operators of existing affected sources 

may demonstrate compliance by 

emissions averaging for existing EGUs 

that are located at the same facility that 

are within a single subcategory and that 

rely on emissions testing as the 

compliance demonstration method. In 

response to our request for comments on 

the suitability of emissions averaging 

and need for a discount factor, we 

received a range of suggestions, 

including requests for clarification 

regarding eligibility, points for and 

against the need for a discount factor, 

and suggestions to ease implementation. 


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315As long as required emission rates are 

designed to account for factors such as changes in 

averaging times. 

As we noted at proposal, part of the 

EPA’s general policy of encouraging the 

use of flexible compliance approaches 

where they can be properly monitored 

and enforced is to include emissions 

averaging. Emissions averaging can 

provide sources the flexibility to comply 

in the least costly manner while still 

maintaining a regulation that is 

workable and enforceable. Emissions 

averaging would not be applicable to 

new affected sources and could only be 

used between EGUs in the same 

subcategory at a particular facility. Also, 

owners or operators of existing sources 

subject to the EGU NSPS (40 CFR part 

60, subparts D and Da) would be 

required to continue to meet the PM 

emission standard of that NSPS 

regardless of whether or not they are 

using emissions averaging (i.e., an EGU 

subject to 40 CFR part 60, subpart D or 

Da must meet its applicable NSPS 

filterable PM emission limit even if it is 

included in a 40 CFR part 63, subpart 

UUUUU, emissions averaging group for 

filterable PM). 

Emissions averaging allows owners 

and operators of a facility that includes 

existing EGUs within a subcategory to 

demonstrate that the source complies 

with the proposed emission limits by 

averaging the emissions from an 

individual affected EGU that is emitting 

above the proposed emission limits with 

other affected EGUs at the same facility 

that are emitting below the proposed 

emission limits and that are within the 

same subcategory. Although some 

commenters note that the MACT limits 

are low, based on the data available to 

the Agency, we believe that dozens of 

existing EGUs are achieving all of the 

limits and, thus, emissions averaging is 

a possible approach. 

The final rule includes an emissions 

averaging compliance alternative 

because emissions averaging 315

represents an equivalent, more flexible, 

and less costly alternative to controlling 

certain emission points to MACT levels. 

We have concluded that averaging in 

the proposed rule could be 

implemented and that it would not 

lessen the stringency of the MACT floor 

limits and would provide flexibility in 

compliance, cost and energy savings to 

owners and operators. We also 

recognize that we must ensure that any 

emissions averaging option can be 

implemented and enforced, will be clear 

to sources, and most importantly, will 

be no less stringent than unit-by-unit 

implementation of the MACT floor 

limits. 

In the final rule, the EPA is providing 

that sources may average emissions 

from existing EGUs at the same facility 

and within the same subcategory. 

Further, for Hg emissions only from 

existing EGUs within the same 

subcategory, such EGUs in an emissions 

averaging plan may use an alternate 

compliance approach consisting of a 90- 

boiler operating day rolling average 

emission limit of 1.0 lb/TBtu or 1.1E–2 

lb/GWh. 

In the memo entitled ‘‘The Impact of 

Emission Averaging Time on the 

Stringency of an Emission Standard’’ in 

the docket, we have illustrated why a 

longer-term average results in a lower 

limit. In essence, longer-term averages 

allow particularly high (or low) 

measurements to be averaged with many 

more measurements closer to the mean. 

This results in the highest averages from 

a longer-term averaging period (e.g., 90 

days) being lower than the highest 

averages in a shorter term averaging 

period (e.g., 30 days). 

We have illustrated this concept by 

taking Hg CEMS data and calculating 

rolling 30-day averages and rolling 90- 

day averages. The 30-day averages have 

greater variability and, thus, higher 

peaks and valleys. The 90-day average 

has less variability; therefore, the same 

unit is able to meet a tighter 90-day 

limit. 

The EPA is providing this alternate 

90-day rolling average compliance 

approach for Hg only. A 90-day rolling 

average is appropriate for Hg, and only 

for Hg, because the health and 

environmental impacts associated with 

Hg are related to environmental loading 

rather than shorter term inhalation or 

other acute exposure, as is the case with 

HCl and PM. We believe that this 

alternative compliance approach will 

provide at least the same level of 

environmental protection while 

allowing companies greater flexibility to 

use emissions averaging. For example, 

such an approach would allow for the 

averaging of an infrequently operated 

unit that is operating slightly above the 

standard with a more frequently 

operated unit that is operating below the 

standard in the instances when the more 

frequently operated unit is in a multiday or multi-week maintenance outage. 

The EPA has concluded that it is 

permissible to establish within a 

NESHAP a unified compliance regimen 

that permits averaging within the same 

facility across individual existing EGUs 

subject to the same standards under 

certain conditions. As mentioned 

earlier, individual EGUs within an 

emissions averaging group would be 

allowed to have emissions greater than, 

less than, or equivalent with the 

emissions limit for their subcategory, 

provided that the average emissions 

comprised from individual EGU 

emissions do not exceed the emissions 

limit for their subcategory. Averaging 

across affected units is permitted only if 

it can be demonstrated that the total 

quantity of any particular HAP that may 

be emitted by that portion of a 

contiguous major source that is subject 

to the same standards in the NESHAP 

will not be greater under the averaging 

mechanism than it could be if each 

individual affected EGU in the 

subcategory complied separately with 

the applicable standard. Under this test, 

the practical outcome of averaging is 

equivalent to compliance with the 

MACT floor limits by each discrete 

EGU, and the statutory requirement that 

the MACT standard reflect the 

maximum achievable emissions 

reductions is, therefore, fully 

effectuated. 

As noted in the proposal preamble, in 

past rulemakings, the EPA has generally 

imposed certain limits on the scope and 

nature of emissions averaging programs. 

These limits include: (1) No averaging 

between different types of pollutants; (2) 

No averaging between sources that are 

not part of the same affected source; (3) 

No averaging between individual 

sources within a single major source if 

the individual sources are not subject to 

the same NESHAP; and (4) No averaging 

between existing sources and new 

sources. 

The final rule fully satisfies each of 

these criteria. First, emissions averaging 

would only be permitted between 

individual existing sources at a single 

stationary source (i.e., the facility), and 

would only be permitted between 

individual sources in the same 

subcategory in the final EGU NESHAP. 

Further, emissions averaging would not 

be permitted between two or more 

different affected sources. Finally, new 

affected sources could not use emissions 

averaging. Accordingly, we have 

concluded that the averaging of 

emissions across affected units in the 

same existing source subcategory is 

consistent with the CAA. In addition, 

the final rule requires each facility that 

intends to utilize emissions averaging to 

develop an emissions averaging plan, 

which provides additional assurance 

that the necessary criteria will be 

followed. In this emissions averaging 

plan, the facility must include the 

identification of: (1) All units in the 

averaging group; (2) the control 

technology installed; (3) the process 

parameter that will be monitored; (4) the 

specific control technology or pollution 


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316The EPA has reviewed monitoring data 

submitted to the Agency under the Title IV Acid 

Rain Program. Based on that review, the EPA is 

unaware of any coal- and oil-fired units that share 

a common stack. 

317Hazardous Organic NESHAP (59 FR 19,425; 

April 22, 1994). 

prevention measure to be used; (5) the 

test plan for the measurement of the 

HAP being averaged; and (6) the 

operating parameters to be monitored 

for each control device. A state, local, or 

tribal regulatory agency that is delegated 

authority for this rule could require the 

emissions averaging plan to be 

submitted or even approved before 

emissions averaging could be used. 

Upon receipt, the regulatory authority 

would not be able to approve an 

emissions averaging plan differing from 

the eligibility criteria contained in the 

rule. 

The final rule excludes new affected 

sources from the emissions averaging 

provision. The EPA does not believe the 

statute authorizes emissions averaging 

for new affected sources. One reason we 

allow emissions averaging is to give 

existing sources flexibility to achieve 

compliance at diverse points with 

varying degrees of add-on control 

already in place in the most costeffective and technically reasonable 

fashion. 

With the monitoring and compliance 

provisions that are being finalized, there 

is additional assurance that the 

environmental benefit will be realized. 

Further, the emissions averaging 

provision would not apply to individual 

EGUs if the EGU shares a common stack 

with units in other subcategories, 

because in that circumstance it is not 

possible to distinguish the emissions 

from each individual unit.316

The rule allows EGUs that rely on 

CEMS for compliance demonstrations to 

be able to participate in emissions 

averaging and the emissions limits are 

not subject to a discount. The EPA 

believes that the data certainty provided 

by units that use CEMS would be ideal 

for emissions averaging and the 

flexibility and cost-effectiveness it 

offers. Given the homogeneity of fuels 

within the rules subcategories, along 

with other emissions averaging criteria, 

the Agency believes use of a discount 

factor to be unwarranted for this rule. 

The emissions averaging provisions in 

this final rule are based in part on the 

emissions averaging provisions in the 

Hazardous Organic NESHAP (HON). 

The legal basis and rationale for the 

HON emissions averaging provisions 

were provided in the preamble to the 

final HON.317 We do not believe that we 

have the authority to provide for 

emissions averaging among EGUs in 

different subcategories or among EGUs 

not physically located at the same 

affected facility. 

I. Notification, Recordkeeping, and 

Reporting 

Compared to the proposed rule, the 

reduced continuous compliance 

requirements in the final rule— 

primarily reduced testing frequencies 

and removal of fuel analyses and control 

device or fuel operating parameter 

monitoring—considerably reduces the 

overall burden associated with 

recordkeeping and reporting. Based on 

evaluation of the comments received, 

we have established a provision in the 

final rule for submission of most CEMS 

data (including monitoring plan, 

emissions data, and QA data) through 

ECMPS, so that the affected industry 

uses a common reporting tool for 

submitting CEMS data. 

For data other than most CEMS data, 

the final rule requires electronic 

reporting of certain data, including 

performance test reports, PM CPMS 

data, PM CEMS data, and, if approved 

as part of an alternative monitoring 

request, HAP metals CEMS data. Other 

reports, such as notifications, must be 

submitted in hard copy format or in 

accordance with the procedures 

established by state and local agencies 

that receive delegation for implementing 

this rule. In the proposed rule, we took 

comment on these approaches and 

stated our anticipation of adopting these 

approaches. In the final rule, we have 

extended the ECMPS reporting to most 

CEMS data to promote harmonization 

for CEMS data from the industry, while 

leaving reporting of non-CEMS data in 

a separate reporting system. 

J. Technical/Editorial Corrections 

In this final action, we are making a 

number of technical corrections and 

clarifications to 40 CFR part 63, subpart 

UUUUU. These changes clarify 

procedures for implementing the 

emission limitations for affected 

sources. We are also clarifying several 

definitions to help affected sources 

determine applicability of this rule. We 

have modified some proposed 

regulatory language based on public 

comments. In addition, in response to 

comments received (including the May 

2010 notice from the Utility Air 

Regulatory Group (UARG) of calculation 

errors in the proposed Hg MACT floor 

limits), we have checked all calculations 

and made corrections where necessary. 

In several places throughout the 

subpart, including the associated tables, 

we have corrected the cross-references 

to other sections and paragraphs of the 

subpart. 

VII. Public Comments and Responses to 

the Proposed NESHAP 

A. MACT Floor Analysis 

1. New Data/Technical Corrections to 

Old Data 

Comment: Many commenters 

identified errors in the emissions 

database compiled through information 

provided by industry in response to the 

2010 information collection request 

(ICR) that supported development of 

this rule. Commenters submitted 

corrections to the EPA during the public 

comment period. 

Response: The EPA has incorporated 

technical corrections and new data 

submitted prior to the end of the 

comment period. The corrections and 

new data are described in detail in a 

memorandum in the docket. The EPA 

re-ranked the sources in the MACT floor 

pools to the extent necessary based on 

the new or corrected data, and we 

recalculated the MACT floors as 

necessary based on the re-ranking of 

sources. The revised MACT floors were 

established using the same methodology 

set forth in the proposed rule. 

2. Pollutant-by-Pollutant Approach 

Comment: Many commenters raised 

concerns about the way the EPA 

determined the MACT floors using a 

pollutant-by-pollutant approach. 

Commenters contended that such a 

methodology produced limits that are 

not achievable in combination, and as 

such, the limits do not comport with the 

intent of the statute or the recent court 

decision (NRDC v. EPA, 2007). 

Commenters further added that the CAA 

directs the EPA to set standards based 

on the overall performance of ‘‘sources’’ 

and CAA sections 112(d)(1), (2), and (3) 

specify that emissions standards be 

established on the ‘‘in practice’’ 

performance of a ‘‘source’’ in the 

category or subcategory. Commenters 

stated that if Congress had intended for 

the EPA to establish MACT floor levels 

considering the achievable emission 

limits of individual HAP, it could have 

worded CAA section 112(d)(3) to refer 

to the best-performing sources ‘‘for each 

pollutant.’’ Many commenters added 

that the EPA’s discretion in setting 

standards is limited to distinguishing 

among classes, types, and sizes of 

sources. Commenters contend that 

although Congress limited the EPA’s 

authority to parse units and sources 

with similar design and types, it does 

not allow the EPA to ‘‘distinguish’’ units 

and sources by individual pollutant as 

proposed in this rule (Sierra Club v. 

EPA, 551 F.3d 1019, 1028 (D.C. Cir. 

2008)). By calculating each MACT floor 


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318See Petitioners Brief in Medical Waste 

Institute et al. v. EPA, No. 09–1297 (D.C. Cir.) 

pointing out, in this context, that ‘‘the best 

performers for some pollutants are the worst 

performers for others’’ (p. 34) and ‘‘[s]ome of the 

best performers for certain pollutants are among the 

worst performers for others.’’ 

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 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 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 subsilentio mandating a different result 

when it left the provision ambiguous on 

this issue. The argument that MACT 

floors set HAP-by-HAP are based on the 

performance of a hypothetical facility, 

so that the limitations are not based on 

those achieved in practice, just 

reiterates the question of whether CAA 

section 112(d)(3) refers to whole 

facilities or individual HAP. All of the 

limitations in the floors in this rule 

reflect sources’ actual performance and 

were achieved in practice. As to 

commenters’ claims that standards set 

in this manner cannot be met by any 

actual sources, we have determined that 

there are approximately 69 existing 

coal-fired EGUs that meet all of the final 

existing source MACT emission limits 

(out of 252 EGUs that reported data for 

Hg, PM, and HCl in the 2010 ICR) and 

at least one EGU that meets all of the 

final new source MACT emission limits. 

Commenters also point to the EPA’s 

subcategorization authority, and claim 

that because Congress authorized the 

EPA to distinguish among classes, types, 

and sizes of units, the EPA cannot 

distinguish units by individual 

pollutant, as they allege the EPA did in 

the proposed rule. However, that 

statutory language addresses the EPA’s 

authority to subcategorize sources 

within a source category prior to setting 

standards, which the EPA has done for 

certain EGUs. The EPA is not 

distinguishing within each subcategory 

based on HAP emitted. Rather, it is 

establishing emissions standards based 

on the emissions limits achieved by 

units in each subcategory. Therefore, the 

EPA’s subcategorization authority is 

irrelevant to the question of how the 

EPA establishes MACT floor standards 

once it has made the decision to 

distinguish among sources and create 

subcategories. 

The EPA’s long-standing 

interpretation of the Act is that the 

existing and new source MACT floors 

are to be established on a HAP-by-HAP 

basis. One reason for this interpretation 

is that a whole plant approach could 

yield least common denominator 

floors—that is, floors reflecting limited 

or no control, rather than performance 

which is the average of what best 

performers have achieved. See 61 FR 

173687 (April 19, 1996); 62 FR 48363– 

64 (September 15, 1997) (same approach 

adopted under the very similar language 

of CAA section 129(a)(2)). Such an 

approach would allow the performance 

of sources that are outside of the bestperforming 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 and the best performers for 

acid gas HAP were the worst performers 

for HAP metals, the floor for acid gases 

or metals would end up not reflecting 

best performance. In such a situation, 

the EPA would have to make a value 

judgment as to which pollutant 

reductions were most critical to decide 

which sources are best controlled.318

Such value judgments are antithetical to 

the direction of the statute at the MACT 

floor-setting stage. 

Commenters suggested that a multipollutant 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 


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319Because 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. 

that only control some of these 

pollutants effectively guts the standards 

by including worse performers in the 

averaging process, whereas the EPA’s 

interpretation promotes the evident 

Congressional objective of having the 

floor reflect the average performance of 

best performing sources. Because 

Congress has not spoken to the precise 

question at issue, and the Agency’s 

interpretation effectuates statutory goals 

and policies in a reasonable manner, its 

interpretation must be upheld. See 

Chevron v. NRDC, 467 U.S. 837 

(1984).319

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 technologybased 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) 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 the 

use of fewer data points for large source 

categories than for small source 

categories where the Administrator only 

has emissions information on a small 

number of units for categories and 

subcategories with 30 or more sources. 

Furthermore, commenters contend that 

Congress could not have intended the 

floors for a subcategory with 29 sources 

to be based on 5 sources and a 

subcategory with 31 sources to be based 

on less than that number; but we 

maintain this contention is without 

merit because 12 percent of 31 is 3.72 

(rounded to 4) so the EPA would not 

base standards for a subcategory with 31 

sources on 5 sources even if we had data 

on all 31 sources in the subcategory. For 

these reasons, we decline to adopt 

commenters’ position and continue to 

adhere to the clear statutory directive. 

4. Treatment of Detection Levels 

Comment: Commenters stated that 

when setting the MACT floors, nondetect values are present in many of the 

datasets from best performing units. 

Commenters provided input on how 

these non-detect 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. 

Some commenters stated it is 

necessary to keep the data as reported 

because changing values would lead to 

an upward bias. Additional commenters 

agreed with this basic premise, but 

suggested that replacing non-detect data 

with a value of half the MDL is 

appropriate while still minimizing the 

bias. They noted that treating 

measurements below the MDL as 

occurring at the MDL is statistically 

incorrect and violates the statute’s 

‘‘shall not be less stringent than’’ 

requirement for MACT floors. One 

commenter also provided a reference for 

a statistical method based on a lognormal 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 recovery, and sample analysis; 


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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. 

Commenters stated that where the 

proposed MACT floor is below the LOQ 

or PQL then that source category has a 

technological measurement limitation. 

A few commenters suggested RL values 

should be used when developing the 

floor limits. They stated that the RL is 

the lowest level at which the entire 

analytical system gives reliable signals 

and includes an acceptable calibration 

point. They added that use of an 

acceptable calibration point is critical in 

showing that numbers are real versus 

multiplying the MDL by various factors. 

Several commenters stated that all 

non-detect values should be excluded 

from MACT floor calculations. They 

believed that excluding all non-detect 

values would eliminate any potential 

errors or accuracy issues related to 

testing for compliance. Due to 

inconsistencies of the MDL value 

reported for non-detect data, one 

commenter suggested treating all such 

values as zero. This would provide a 

consistent approach for setting the floor 

as well as determining compliance. 

Several commenters provided input 

on the EPA’s proposed method of three 

times the MDL as an option for setting 

limits. A few commenters in support 

noted that this approach provided a 

reasonable method to account for data 

variability as it took into account more 

than just analytical instrument 

precision. Many other commenters 

argued that this method results in limits 

which are too low, namely that it is still 

lower than the LOQ value which they 

are in favor of as a substitute for any 

reported non-detect data. Other 

commenters disagreed with this method 

and claimed that it would lead to results 

which introduce a high bias in the floor 

setting process. A few contended that 

multiplying by 3 would introduce a 300 

percent error into the floor, resulting in 

a floor that is less stringent than 

required by the Act. Others suggested 

that the MDL values are antiquated and 

already too high and thus it is not 

appropriate to multiply them by three. 

Also, a few commenters suggested 

multiplying the 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 the 

comments related to treatment of data 

reported as detection limit values in the 

development of MACT floors and 

emissions limits. As we noted at 

proposal, the statistical probability 

procedures applied in calculating the 

floor or an emissions limit inherently 

and reasonably account for emissions 

data variability including measurement 

imprecision when the database 

represents multiple tests from multiple 

emissions units for which all of the data 

are measured significantly above the 

method detection level. That is less true 

when the database includes emissions 

occurring below method detection 

capabilities regardless of how those data 

are reported. 

The EPA’s guidance to respondents 

for reporting pollutant emissions used 

to support the data collection specified 

the criteria for determining test-specific 

method detection levels. Those criteria 

ensure that there is only about a 1 

percent probability of an error in 

deciding that the pollutant measured at 

the method detection level is present 

when in fact it was absent. (Reference: 

ReMAP: PHASE 1, Precision of Manual 

Stack Emission Measurements; 

American Society of Mechanical 

Engineers, 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 × 

standard deviation of the true 

concentration. The anticipated range for 

the average of repeated measurements 

comes progressively closer to the true 

concentration. More precisely, the 

anticipated range varies inversely with 

the square root of the number of 

measurements. Thus, for a known 

standard deviation (SD) of anticipated 

single measurements, the anticipated 

range for 99 out of 100 future triplicate 

measurements will fall within ±2.54 SD/ 

√3 of the true concentration. This 

relationship translates to an expected 

measurement imprecision for an 

emissions value occurring at or near the 

method detection level of about 40 to 50 

percent. 

By assuming a similar distribution of 

measurements across a range of values 

and increasing the mean value to a 

representative higher value (e.g., 3 times 

minimum detection level or 3xMDL), 

we can estimate measurement 

imprecision at other levels. For an 

assumed 3xMDL, the estimated 

measurement imprecision for a three 

test run average value would be on the 

order 10 to 20 percent. This is about the 

same measurement imprecision as 

found for Methods 23 and 29 indicated 

in the ASME ReMAP study for the 

sample volumes prescribed in the final 

rule (e.g., 4 to 6 dscm) for multiple tests. 

Analytical laboratories often report a 

value above the method detection limit 

that represents the laboratory’s 

perceived confidence in the quality of 

the value. This independently adjusted 

value is expressed differently by various 

laboratories and is called LOQ, PQL, or 

RL. In many cases, the LOQ, PQL, or RL 

is simply a multiplication of the method 

detection limit. Commonly used 

multipliers range from 3 to 10. Because 

these values reflect individual 

laboratories’ perceived confidence, and, 

therefore, could be viewed as arbitrary, 

we decline to adopt the LOQ, PQL, or 

RL because such approaches in our view 

would inappropriately inflate the MACT 

floor standards. Our alternative to those 

inconsistent approaches is discussed 

below. 

Consistent with findings expressed in 

reports of emissions measurement 

imprecision and the practices of 

analytical laboratories, we believe that 

using a measurement value of 3 times a 

representative method detection limit 

established in a manner that assures 99 

percent confidence of a measurement 

above zero will produce a representative 

method reporting limit suitable for 

establishing regulatory floor values. 

On the other hand, we also agree with 

commenters that an emissions limit set 

from a small subset of data or data from 

a single source may be significantly 

different than the actual method 

detection levels achieved by the best 

performing units in practice. This fact, 

combined with the low levels of 

emissions measured from many of the 

best performing units, led the EPA since 

proposal to review and revise the 

procedure intended to account for the 

contribution of measurement 

imprecision to data variability in 

establishing effective emissions limits. 

In response to the comments about the 


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quality of measurements at very low 

emissions limits especially for new 

sources, we revised the procedure for 

identifying a representative method 

detection level (RDL). 

The revised procedure for 

determining an RDL starts with 

identifying all of the available reported 

pollutant-specific method detection 

levels for the best performing units 

regardless of any subcategory (e.g., 

existing or new, fuel type, etc.). From 

that combined pool of data, we calculate 

the arithmetic mean value. By limiting 

the data set to those tests used to 

establish the floor or emissions limit 

(i.e., best performers), which in this case 

is a larger data set than normally 

available for establishing NESHAP, we 

believe that the result is representative 

of the best performing testing companies 

and laboratories using the most 

sensitive analytical procedures. We 

believe that the outcome should 

minimize the effect of a test(s) with an 

inordinately high method detection 

level (e.g., the sample volume was too 

small, the laboratory technique was 

insufficiently sensitive, or the procedure 

for determining the minimum value for 

reporting was other than the detection 

level). We then call the resulting mean 

of the method detection levels the 

representative detection level (RDL) 

because it is characteristic of accepted 

source emissions measurement 

performance. 

The second step in the process is to 

calculate 3xRDL to compare with the 

calculated floor or emissions limit. This 

step is similar to what we have used for 

other NESHAP including the Portland 

Cement rule. As outlined above, we use 

the multiplication factor of 3 to reduce 

the imprecision of the analytical method 

until the imprecision in the field 

sampling reflects the relative method 

precision as estimated by the ASME 

ReMAP study. That study indicates that 

such relative imprecision remains a 

constant 10 to 20 percent over the range 

of the method. For assessing the 

calculated floor results relative to 

measurement method capabilities, if 

3xRDL were less than the calculated 

floor or emissions limit (e.g., calculated 

from the upper predictive limit, UPL), 

we would conclude that measurement 

variability was adequately addressed 

with the initial floor calculation. The 

calculated floor or emissions limit 

would need no adjustment. If, on the 

other hand, the value equal to 3xRDL 

were greater than the UPL, we would 

conclude that the calculated floor or 

emissions limit did not account entirely 

for measurement variability. Where 

such was the case, we substituted the 

value equal to 3xRDL for the calculated 

floor or emissions limit (UPL) which 

results in a concentration where the 

method would produce measurement 

accuracy on the order of 10 to 20 

percent similar to other EPA test 

methods and the results found in the 

ASME ReMAP study. 

We determined the RDL for each 

pollutant using data from tests of all the 

best performers for all of the final 

regulatory subcategories (i.e., pooled 

test data). We applied the same 

pollutant-specific RDL and emissions 

limit assessment and adjustment 

procedures to all subcategories for 

which we established emissions limits. 

We believe that adjusting emissions 

limits in this manner, which ensures 

that measurement variability is 

adequately addressed relative to 

compliance determinations, is a better 

procedure than the one applied at 

proposal, which was based on more 

limited data. We also believe that 

currently available emissions testing 

procedures and technologies provide 

the measurement certainty sufficient for 

sources to demonstrate compliance at 

the levels of the revised emissions 

limits. 

5. Basis for New Source MACT 

Comment: Several commenters stated 

that the proposed limits set for new 

EGUs do not represent the best 

performing EGU. The commenters state 

that the EPA has chosen the strictest 

limit irrespective of the EGU and that 

limits for new EGUs should be 

achievable. According to the 

commenters, no existing EGU is 

currently meeting the proposed limits, 

which will result in a moratorium on 

the construction of new coal-fired EGUs. 

Further, commenters state that another 

result of the EPA’s flawed approach is 

that the proposed standards for new 

EGUs are so low that adequate test 

methodologies to demonstrate 

compliance do not exist. Without 

accurate testing methodologies, 

commenters assert that contractors will 

not guarantee that potential emission 

control technologies will meet the 

proposed standards. Without accurate 

test methodologies and vendor 

guarantees, commenters believe that 

financing of new facilities will be 

virtually impossible to secure which 

will, in turn, effectively preclude the 

construction of any new coal-based 

EGUs. 

Commenters also stated that the EPA 

failed to address cumulative effects of 

using multiple pollution control devices 

in determining MACT levels applicable 

to PM levels. In proposing total PM as 

a surrogate, commenters believe that the 

EPA failed to consider or address the 

antagonistic effects that adding multiple 

pollution control devices can have on 

an EGU’s HAP emissions. Commenters 

indicated that EGUs would not be able 

to comply with the proposed new 

source HCl limit without adding a 

scrubber or some type of sorbent 

injection to control HCl emissions. 

Adding these HCl control technologies 

will increase the total PM emissions of 

these units. According to commenters, 

because a fabric filter-alone 

configuration (the basis for the new 

source PM limit) would not meet all 

MACT limits, these units may not be the 

best-performing units. 

Response: The EPA disagrees with the 

commenters’ statements that no existing 

unit is currently meeting the new source 

limits. The EPA established the new 

source limits based on data from 

existing EGUs and there is at least one 

EGU, based on the data available, that 

is meeting all three final HAP limits and 

at least eight EGUs that are meeting one 

or more of the new source limits. As a 

result of comments received on the full 

body of data, the EPA has re-ranked the 

best performing EGUs and reviewed the 

new source limits based on the reranking where appropriate. Based on the 

revised ranking, the best performing 

source for PM has changed and that 

source now forms the basis for the new 

source filterable PM limit in the final 

rule. The source is a coal-fired EGU that 

includes the entire suite of controls that 

would likely be required on a new coalfired source constructed prospectively 

(i.e., it is a unit with SCR, dry FGD, and 

FF). Thus, the commenters’ concerns are 

no longer relevant as they relate to PM 

emissions from coal-fired EGUs. 

The EPA also believes that the EGUs 

serving as the basis for the new source 

Hg and HCl limits in the final rule are 

representative of what a new coal-fired 

EGU would look like to meet all of the 

requisite regulations applicable to EGUs 

(e.g., NSPS and the CSAPR) as they also 

include the entire suite of controls that 

would likely be required on a new coalfired source constructed prospectively. 

The EPA has also taken into account the 

ability of the various test methods to 

accurately measure emissions at the 

levels being demonstrated by the EGUs 

in the top performing 12 percent in 

establishing the final limits, and we 

have determined that there are adequate 

test methods to measure the regulated 

HAP at the new source levels. 

6. Achievability of Limits 

Comment: A number of commenters 

state that the EPA has chosen the 

strictest limit irrespective of the unit 

and that limits for new EGUs should be 

achievable. According to the 


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commenters, no existing unit is 

currently meeting the proposed new 

source limits, which will result in a 

moratorium on the construction of new 

coal-fired units. The commenters state 

that this regulation goes beyond 

protecting public health and will impact 

the country’s choice of fuel for energy 

production. Other commenters state that 

another result of the EPA’s flawed 

approach is that the proposed standards 

for new units are so low that adequate 

test methodologies to demonstrate 

compliance do not exist. Without 

accurate testing methodologies, 

commenters allege that contractors will 

not guarantee that potential emission 

control technologies will meet the 

proposed standards. Without accurate 

test methodologies and vendor 

guarantees, commenters believe that 

financing of new facilities will be 

virtually impossible to secure, and that 

this in turn will effectively preclude the 

construction of any new coal-based 

units. Commenters maintain that 

adopting standards effectively banning 

new coal units amounts to a momentous 

change in national energy policy 

without discussion or analysis and far 

exceeds the EPA’s authority. 

Some commenters add that the 

proposed new source MACT standards 

do not represent rates that have been 

achieved in practice and are orders of 

magnitude lower than any of the CAA 

section 112(g) case-by-case MACT limits 

established for the most advanced units 

in the U.S. coal fleet by multiple state 

agencies. 

Other commenters stated that the 

synergistic impact of multiple controls 

has not been taken into account in the 

proposed rules. Commenters argue that 

circumstances exist with respect to the 

control of acid gases, which will require 

scrubbers or other SO2 controls that add 

particulate to the flue gas stream, and 

that added particulate must be removed 

by PM control devices along with the 

particulate added to the flue gas for 

EGUs that need to install ACI for Hg 

control. Because particulate devices 

provide a fixed percent reduction of 

particulate, commenters assert that it is 

mathematically certain that PM 

performance will decrease because 

control of both acid gases and Hg would 

add PM to the flue gas stream which 

would in turn decrease performance of 

the PM control on the relevant mass 

metric. As a consequence, commenters 

allege that there is no assurance that 

sources can meet the EPA’s ‘‘cherrypicked’’ floors for acid gases and for Hg 

by ‘‘optimizing’’ these systems to meet 

the performance of the floor units 

because to do so would impact their 

ability to meet the EPA’s similarly 

‘‘cherry-picked’’ total PM floor standard. 

The commenters state that, for 

existing sources as with the new source 

standard-setting approach, a pollutantby-pollutant approach does not consider 

what the top performing 12 percent 

achieve in practice for all pollutants and 

does not consider the antagonistic 

effects of the concurrent use of various 

control technologies. For example, one 

commenter states that 47 of the 131 

sources used to calculate the existing 

source total PM limit only had PM 

control but no acid gas or Hg controls 

that could emit additional PM. 

According to the commenter, the CAA 

is clear that standards must be based on 

actual sources and not the product of a 

pollutant-by-pollutant determination 

resulting in a set of composite standards 

that do not necessarily reflect the 

overall performance of any actual 

source. To address these issues, the 

commenter recommends that the EPA 

use an approach that more accurately 

reflects what actual best performing 

sources achieve. 

Response: The EPA disagrees with the 

commenters’ contention that the 

pollutant-by-pollutant approach to 

establishing MACT floors is inconsistent 

with the CAA for the reasons set forth 

in the response to comments on the 

EPA’s MACT floor setting process. In 

addition, the EPA established the 

proposed new source limits based on 

data from existing EGUs, and there are 

EGUs that are able to meet the new 

source limits. To the extent the 

commenters are concerned that no 

existing source is simultaneously 

meeting all of the new sources limits, 

we note that the EPA has revised the 

new source standards based on 

comments and data corrections that 

industry made to data it incorrectly 

provided in response to the utility ICR. 

We have identified at least one source 

that is meeting all of the new source 

MACT limits in the final rule. 

We disagree with commenters that 

suggest the proposed new source 

standards are invalid because they are 

more stringent than CAA section 112(g) 

case-by-case MACT limits established 

by state agencies. As commenters note, 

states, not the EPA, established the CAA 

section 112(g) standards, and they did 

so based on the information available to 

them. The EPA likewise must establish 

CAA section 112(d) standards based on 

the available data. We have considered 

the available data and information, 

including the 2010 ICR data, and 

complied with the requirements of CAA 

section 112(d) in establishing the 

standards in this final rule. That the 

final standards are more stringent than 

CAA section 112(g) standards issued by 

certain state agencies has no bearing on 

the legitimacy of the standards at issue 

here. 

The EPA agrees with commenters that 

the SO2 and some Hg controls may add 

to the PM loading and that it is 

reasonable to establish the new source 

standard based on an EGU that has a 

suite of controls that will be required of 

any new source. For example, new coalfired 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). 

The final standard is not based on the 

source used to establish the proposed 

limit. As stated above, industry 

commenters provided data corrections 

and new data and the EPA considered 

that new and revised data in 

establishing the final standards. We reranked all the coal-fired EGUs based on 

the new data. The new ranking of coalfired EGUs resulted in a change of the 

source we used to establish the new 

source PM surrogate standard for nonmercury 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 

coal-fired generation as indicated by the 

commenter. 

The EPA also disagrees that the final 

new source standards are so stringent 

that there are not adequate test methods 

available to determine compliance with 

the standards. The EPA has taken into 

account the ability of the various test 

methods to accurately measure 

emissions at the levels being 

demonstrated by the best performing 

EGUs in establishing the final limits. 

This has been done through use of the 

3XRDL (discussed elsewhere in this 

preamble and the Response to 

Comments document) and through 

adjustments to the sampling time 

requirements for certain of the HAP. 

7. Comments on Technical Approaches 

Comment: Commenters disagreed 

with the EPA’s use of data from 

multiple units exhausting through a 

common stack and argued that the EPA 

unreasonably treated data from multiple 


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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 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 majorsource Industrial Boiler NESHAP, the 

EPA argued its approach of creating two 

data points from a single combined 

stack data point is reasonable because it 

cannot separate the comingled fraction 

of the emissions from the different 

emission points. Commenters state that 

this is irrelevant, believing that there is 

no basis to separate these emissions 

because the MACT floor is based on best 

performing sources and there is only a 

single source. 

According to commenters, the EPA 

cannot determine what amount of the 

overall performance of a combined stack 

data point is the specific result of the 

combination. Commenters assert that 

the EPA also argues that applying the 

emissions equally to multiple units 

exhausting through a single stack 

‘‘accurately represents the emissions of 

those units on average.’’ Commenters 

believe that is simply not correct and 

there is no plausible factual basis for 

that statement, believing that there is no 

unit that ‘‘achieved’’ those emissions. 

Rather, the data represent the combined 

weighted average of two units, without 

knowing how either unit actually 

performed. One commenter also stated 

that in several instances when a facility 

operated tandem or multiple EGUs but 

only submitted a single stack 

measurement, the EPA used the single 

stack measurement to represent Hg 

emissions from the facility’s other 

stacks. 

Response: The EPA disagrees with 

commenters. As in the major-source 

Industrial Boiler NESHAP, the EPA 

continues to believe that the emissions 

from the common stack represent the 

average emissions of the EGUs 

exhausting to the common stack and are 

representative of both EGUs. 

Commenters have provided no data to 

support the contention that this 

assumption is false. In addition, 

commenters’ contention that distinct 

EGUs (i.e., boilers) are one source if they 

emit out of a common stack is not 

consistent with the CAA section 

112(a)(8) definition, which clearly 

applies to the individual boiler units 

with a capacity of more than 25 MW. It 

would not be reasonable in light of that 

definition to consider the emissions 

from two boilers to a common stack as 

the emissions of one EGU. The EPA 

only used data from combined stacks 

where both EGUs were operating or 

where the owner/operator certified that 

no air leakage could occur. The EPA 

expects that companies will comply 

with the final rule by conducting testing 

at the common stack as that is usually 

where the sampling locations are (rather 

than in the intermediate ductwork) and 

will report the results as being for each 

EGU. 

The EPA has reviewed the data based 

on comments received and does not 

believe that there are any 

inconsistencies in the data set used for 

the final rule. In the MACT floor 

analysis, the EPA only used data from 

stacks that were tested or for which test 

data were provided. These stack 

measurements were not used to 

represent emissions from other, nontested, stacks in the MACT analysis. 

8. Alternative Units for Emission Limits 

Comment: Several commenters 

submitted a variety of alternatives to the 

input- or output-based MACT floor 

limits as means of establishing the 

MACT floors. Some commenters 

suggested emission reductions or 

removal efficiencies. These commenters 

suggest that a percent reduction MACT 

metric be considered as an alternative, 

and not a substitute, to some of the 

proposed MACT numerical limits, 

particularly those that appear too 

problematic to meet in reality. A 

necessary data format and protocol 

could be developed for some HAP, such 

as Hg, that would allow an appropriate 

percent reduction alternative to be 

developed. Commenters believe that the 

Brick MACT decision stands for the 

proposition that a MACT level cannot 

be based on a specific technology; 

commenters are advocating that a 

percent reduction format would specify 

the level or reduction but would not 

dictate any specific control or 

methodology. 

Comments were also received that 

some state programs contain Hg 

emission limits that are more stringent 

than the EPA’s proposed emission 

limits. The programs of Connecticut, 

Massachusetts, New Hampshire, New 

Jersey, and New York were noted. 

Commenters provided information on 

these states’ 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). Such an approach 

would be difficult to implement and 

enforce. Moreover, we do not have the 

data necessary to establish percent 

reduction standards for HAP at this 

time. Depending on what was 

considered to be the ‘‘inlet’’ and the 

degree to which precombustion removal 

of HAP was desired to be included in 

the calculation, the EPA would need 

(e.g.) the HAP content of the coal as it 

left the mine face, as it entered the coal 

preparation facility, as it left the coal 

preparation facility, as it entered the 

EGU, as it entered the control devices, 

and as it left the stack to be able to 

establish percent reduction standards. 

We do not have this type of information. 

The EPA believes that an emission 

rate format allows for, and promotes, the 

use of pre-combustion HAP removal 

processes because such practices will 


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help sources assure they will comply 

with the proposed standard. A percent 

reduction requirement would likely 

limit the flexibility of the regulated 

community by requiring the use of a 

control device. In addition, as discussed 

in the Portland Cement NESHAP (75 FR 

55002; September 9, 2010), the EPA 

believes that a percent reduction format 

negates the contribution of HAP inputs 

to EGU performance and, thus, may be 

inconsistent with the D.C. Circuit’s 

rulings as restated in the Brick case (479 

F.3d at 880) which say, in effect, that it 

is the emissions achieved in practice 

(i.e., emissions to the atmosphere) that 

matter, not how one achieves those 

emissions. 

The 2010 ICR data confirm that plant 

inputs likely play a role in emissions to 

the atmosphere. These data indicate that 

some EGUs are achieving lower Hg 

emissions to the atmosphere at a lower 

Hg percent reduction (e.g., 75 to 85 

percent) than are other EGUs with 

higher percent reductions (e.g., 90 

percent or greater). However, we are not 

sure whether these data accurately 

reflect the total percent reduction mineto-stack because we do not have all the 

data necessary to make that 

determination. Thus, we proposed to 

establish numerical emission standards 

for Hg HAP emissions from EGUs and 

we are finalizing numerical emission 

standards. The same issues prevent us 

from considering percent reduction 

standards for the other HAP emitted 

from EGUs. 

With regard to the comments relating 

to some state programs being more 

stringent than the EPA’s proposed 

limits, the EPA would note that many of 

the programs identified by one 

commenter have an ‘‘either/or’’ format 

for their Hg standards. That is, an EGU 

can either meet an emission limit (e.g., 

lb/TBtu) or achieve a percent reduction. 

The commenter did not note which 

form of the standard the EGUs were 

meeting so it is unclear whether the 

standards are in fact more stringent. In 

any case, CAA section 112(d) does not 

mandate that federal standards be more 

stringent than state requirements for 

HAP emissions. Furthermore, states are 

authorized to establish standards more 

stringent than this final NESHAP so 

promulgation of this rule will in no way 

affect a source’s responsibility to 

comply with an otherwise applicable 

state Hg or other HAP standard. 

9. Beyond-the-Floor 

Comment: Several commenters stated 

that the proposed beyond-the-floor Hg 

limit for low rank coal EGUs is based on 

too little data and is technically and 

economically unattainable, noting that 

the EPA’s proposed beyond-the-floor 

limit is based on only three samples 

from a single test held at only one EGU, 

which is not enough data to develop 

such a limit, especially as more data 

were available for this EGU in the 

database. Commenters noted that 

although this one EGU may have been 

able to achieve the proposed limit 

during this one test, the three samples 

are not adequate to demonstrate the 

long-term ability of this EGU to meet 

that limit consistently, let alone the 

long-term abilities of the top 12 percent 

of all low rank coal EGUs to meet that 

limit consistently. Given Texas lignite’s 

particularly high rates of variability of 

Hg concentration, and the inability to 

minimize this variability, the 

commenters believe that the EPA is 

obliged to have more, not less, data to 

support the proposed beyond-the-floor 

Hg limit for low rank coal EGUs. One 

commenter added that the EPA’s 

decision to require a beyond-the-floor 

limit for the low rank virgin coal 

subcategory does not comply with CAA 

section 112(d)(2). Some commenters 

also contended that the EPA failed to 

include the cost of a baghouse in its 

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 notes that all of 

the low rank virgin coal-fired EGUs for 

which data were submitted in response 

to the 2010 ICR were meeting the Hg 

floor limit (11 lb/TBtu). Four of the 

EGUs have ACI systems installed and 

three of the four EGUs tested were also 

meeting the beyond-the-floor Hg 

emission limit of 4.0 lb/TBtu. Those 

three units were achieving control levels 

of greater than 95 percent (fuel to stack). 

The other low rank virgin coal-fired 

EGUs that are not currently meeting the 

beyond-the-floor emission limit do not 

have installed Hg-specific controls. An 

analysis of the Hg content of the fuel 

used during the 2010 ICR testing 

suggests that control in the range of 80 

to 90 percent (fuel to stack) would be 

needed to meet the beyond-the-floor 

limit of 4.0 lb/TBtu. One low rank virgin 

coal-fired EGU achieved 75 percent 

control with no Hg-specific control 

technology (e.g., ACI). 

The EPA believes that its beyond-thefloor analysis is appropriate, including 

the costs analyzed. The EPA’s cost 

analysis is meant to serve as an average 

for all sources in the subcategory 

recognizing that some EGU’s costs will 

be more and some less; EGUs whose 

costs are higher are not exempted from 

the regulation. Further, five EGUs in the 

subcategory are meeting the final 

beyond-the-floor limit based on 

available data (see the MACT Floor 

analyses in the docket), and, in any 

case, CAA section 112(d) does not 

require that a specified percentage of 

sources in a category or subcategory be 

able to meet the MACT standard that is 

established. This is even truer for 

beyond-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 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-thefloor limit for Hg for new IGCC units. 

The EPA’s choice of the beyond-thefloor 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 for its decision from a 

technology capability assessment. 

Commenters note that ACI for Hg 

treatment of coal-derived syngas is not 

in use in any operating IGCC plant 

today, nor can it be used in the same 

fashion as it is used at conventional 

coal-fired EGUs. Commenters assert that 

the EPA also lacks data with respect to 

new IGCC units, yet the EPA proposed 

beyond-the-floor MACT limits for new 

IGCC sources. The commenters assert 

that the EPA’s limits for new IGCC 

sources are based on beliefs, 

predictions, projections and design 

target assumptions. The limits from the 

2007 DOE Report referenced in the 

preamble are based on environmental 

target assumptions. These IGCC 

environmental targets were chosen to 

match Electric Power Research Institute 

(EPRI) design basis from their Coal Fleet 

for Tomorrow Initiative. Commenter 

states that EPRI notes that these were 

design targets and were not to be used 

for permitting values. Commenters 

assert that the EPA has simply not 

justified its process for going beyondthe-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 


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based on gross energy output from the 

combined cycle generating unit when 

operated with duct burners fired with 

syngas. The 0.068 lb/MWh value is 

consistent with the calculated emission 

ceiling for its permit to construct for this 

operating scenario. According to the 

commenter, there is not sufficient 

experience with syngas turbines for 

manufacturers to guarantee performance 

in the 0.050 lb/MWh range. The 

0.0681b/MWh performance basis 

proposed by the commenter was 

calculated based on the emission 

guarantees that the commenter was able 

to obtain for a turbine fired on the 

syngas. The commenter also requested 

that the 0.050 lb/MWh limit be 

increased to 0.083 lb/MWh based on 

gross energy output from the combined 

cycle unit when operated with duct 

burners fired by natural gas. The 

commenter indicated that, depending 

on market conditions, the syngas 

produced at an IGCC may have more 

value as a raw material for producing 

co-products than it would have as duct 

burner fuel. Where that is the case, the 

economic viability of an IGCC would be 

enhanced by firing the duct burners on 

natural gas and diverting that syngas to 

manufacture of a co-product. The 

commenter’s air permits are currently 

based on the use of syngas as duct 

burner fuel; however, the commenter is 

currently examining an alternative 

operating scenario that may result in 

amendments to the air permits to 

authorize firing natural gas in the duct 

burners. Commenter states that 

preliminary calculations indicate that 

the PM limit would need to be set at 

0.083 lb/MWh gross energy output 

when operated with duct burners fired 

with natural gas. 

The commenter also noted that there 

is not sufficient test data to precisely 

predict the Hg emissions performance of 

even the best-controlled IGCC units, 

other than that IGCC Hg emissions are 

expected to be much less than those for 

EGUs that directly burn coal. In its 

permit application, the commenter 

proposed to establish a new standard for 

Hg removal in IGCC units by treating the 

syngas in catalytic reactors. The 

catalytic reactor system is expected to 

achieve greater than 95 percent Hg 

removal using either sulfur-impregnated 

activated carbon or alumina catalyst. In 

the absence of actual stack test data, the 

commenter has had to estimate expected 

emissions based on engineering 

estimates of how much Hg may arrive in 

the syngas routed to the catalytic 

reactors. Based on these engineering 

estimates and 95 percent Hg removal in 

the catalytic reactors, the commenter 

believes that the resulting Hg emission 

limit for a state-or-the-art IGCC unit 

would be 0.003 lb/GWh, which is much 

less than the Hg emissions for EGUs that 

directly burn coal. 

The commenter notes that IGCC units 

are still in their infancy. Funding for 

them will be very difficult or 

unavailable if there is a regulatory limit 

below the level that can be supported by 

vendor guarantees. Given the important 

role that IGCC units may have in 

meeting global energy and climate 

stability goals, the commenter believes 

it would be a mistake to erect barriers 

to the implementation of this 

technology. The commenter stated that 

the EPA can reevaluate the appropriate 

levels for future IGCC units after 

demonstration units which incorporate 

effective controls have been built and 

tested. 

Response: The EPA is not finalizing 

the proposed new source standards for 

IGCC units. As commenters noted, EPA 

proposed beyond-the-floor limits for 

IGCC units based on the performance of 

PC-fired EGUs and solicited data from 

IGCC units that would represent what a 

new IGCC could achieve. We received 

information that there are new IGCC 

units permitted and under construction. 

The EPA believes one IGCC unit under 

construction for which permit data were 

provided is representative of both 

current technologies and of IGCC units 

that will be built in the near-term future. 

Therefore, the EPA believes these 

permit levels should be the basis of the 

new source IGCC emission limits and 

the Agency is finalizing the PM and Hg 

limits on that basis, as that source will 

be required to comply with its permitted 

limits once constructed and it is a 

similar source. However, permit limits 

were only provided for PM and Hg; 

therefore, the EPA is finalizing the new 

source limits for acid gas HAP based on 

data from the best-performing of the 

existing IGCC units for the respective 

HAP. 

B. Rationale for Subcategories 

Many commenters stated that the EPA 

should have proposed more 

subcategories, while others believed that 

too many subcategories were proposed. 

Many different issues were raised by 

commenters, and some of the key issues 

that were considered in the final rule 

(some of which led to changes in the 

final rule) include: the technical 

deficiencies in the definition for the 

low-Btu coal subcategory; additional 

subcategorization of the coal-fired EGU 

population; the need for 

subcategorization of distillate vs. 

residual oil-fired EGUS; the need for a 

limited-use subcategory for EGUs that 

operate for only a small percentage of 

hours during a year; and the need for a 

non-continental 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 been 

evaluated, including subcategorization 

of other coal ranks, no other coal rank 

subcategorization was proposed. 

Commenters submit there should be 

subcategories for the coal ranks of 

bituminous, subbituminous, and lignite. 

The commenters noted that such 

treatment would be consistent with past 

practice (e.g., CAMR where the 

differences in the type of emissions of 

Hg due to the different chemical 

properties of coal within differing fuel 

ranks was discussed). Commenters note 

that activated carbon has been shown to 

be very effective when used in 

combination with low chlorine coals 

(such as western subbituminous coals); 

however, activated carbons can suffer 

from poor performance when used with 

high sulfur coals. Commenters indicate 

that firing high sulfur coals (especially 

when an SCR is also used) can result in 

sulfur trioxide (SO3) vapor in the flue 

gas stream. The SO3 competes with Hg 

for binding sites on the surface of the 

activated carbon (or unburned carbon) 

and limits the effectiveness of the 

injected activated carbon. But another 

commenter noted that an SO3 mitigation 

technology, such as dry sorbent 

injection (DSI, e.g., trona or hydrated 

lime), applied upstream of the ACI can 

minimize this effect. 

Commenters also stated that without 

further subcategorization the economic 

impacts on individual Midwestern 

states will be particularly acute as huge 

segments of the U.S. coal reserve will be 

disenfranchised by this rule. According 

to the commenters, the EPA did not 

even attempt to legitimately analyze this 

issue and, thus, in their opinion the 

Agency’s proffered rationale for 


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declining to further subcategorize based 

on the acid gas standard is belied by the 

record. The commenters believe that the 

EPA needs to better align this rule with 

its previous position in CAMR and 

further subcategorize based on coal 

type. 

Other commenters are opposed to any 

further subcategorization based on coal 

rank. Because many sources blend 

several ranks of coal on a regular basis, 

commenters believe that establishing 

coal rank subcategories would create 

numerous opportunities for sources to 

game the regulations and substantially 

increase emissions. Commenters stated 

that there is no need for such an 

approach since modern pollution 

controls can accommodate a wide range 

of coals. These commenters believe that 

EGUs firing different ranks of coal are 

not fundamentally different in size, 

class, or type in a way that impacts 

emissions or that limits the availability 

of controls. The commenters believe 

that emissions of fuel-dependent HAP 

can be controlled by either changing the 

fuel prior to combustion or by removing 

the HAP from the flue gas after 

combustion. Commenters state that ACI 

systems, DSI controls, and PM controls 

are available for installation at units 

firing sub-bituminous coal and are 

equally available for units firing 

bituminous, anthracite, or lignite coal. 

These commenters also believe that as 

long as a control option is commercially 

available, the cost for a particular EGU 

is irrelevant to the EPA’s development 

of emission standards based on MACT. 

Commenters stated that subcategories 

based on coal rank would make a 

meaningful consideration of fuel 

switching impossible, contrary to the 

judicial mandate to consider 

substitution of materials in setting the 

floor and the statutory mandate to 

consider substitution of materials in the 

beyond-the-floor analysis. 

One commenter stated that although 

they previously supported the 

subcategorization of coal-fired units on 

the basis of coal rank, they no longer 

object to grouping units that burn 

bituminous and subbituminous coals in 

a single category because the prior basis 

for subcategorization no longer exists. 

The commenter indicated that at the 

time of CAMR, it was widely recognized 

that although coal-fired units 

combusting bituminous coal, with its 

higher concentration of chlorine and, 

therefore, ionic Hg, could effectively 

limit Hg emissions by utilizing existing 

control technologies such as scrubbers, 

units burning subbituminous coal could 

not do so with the same controls 

because of the coal’s higher levels of 

elemental Hg. The commenter stated 

that activated carbon was only a 

fledgling and unproven technology at 

the time; today, however, activated 

carbon has been proven, and units 

burning bituminous and subbituminous 

coal can achieve the same levels of 

emissions for Hg and other HAP. 

Consequently, the commenter believes 

the prior basis for subcategorization no 

longer exists and the commenter, 

therefore, agrees that coal-fired EGUs 

burning bituminous and subbituminous 

coals ought to be grouped in a single 

category. 

Response: The EPA disagrees with 

commenters that additional coal-fired 

subcategories are warranted and has not 

provided any in the final rule. 

Commenters are correct that additional 

subcategorization was proposed in 

January 2004. Whether or not such 

subcategorization was warranted at that 

time, the EPA believes that the current 

conditions are such that, even if 

appropriate at that time, such further 

subcategorization is not appropriate at 

this time. 

When all of the factors noted by 

commenters have been reviewed, with 

the exception of Hg for certain units, as 

discussed above, the EPA does not 

believe that the HAP emissions to the 

atmosphere are sufficiently different 

from coal-fired EGUs to warrant further 

subcategorization. There are EGUs firing 

bituminous, subbituminous, and coal 

refuse among the top performing units 

for Hg and EGUs firing bituminous, 

subbituminous, lignite, and coal refuse 

are all among the top performers for the 

acid gas HAP and non-mercury metallic 

HAP indicating that the MACT floor 

limits established based on these units 

are achievable by units burning all ranks 

of coal. 

As noted by commenters, ACI, not 

fully developed in 2004, is now able to 

effect Hg control levels on 

subbituminous coals such that similar 

emissions to the atmosphere may be 

achieved as those achieved by higherchlorine 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. The EPA does not believe that 

any fundamental discrimination 

between coal ranks will occur as a result 

of the final rule, though clearly some 

sources will be required to install 

greater controls to comply with the final 

standard. We maintain that such result 

is consistent with the intent of CAA 

section 112 standards, which are not 

intended to have an outcome whereby 

all sources can comply with final 

standards without any action. 

The EPA agrees, in theory, that EGUs 

are designed around a basic set of coal 

characteristics. However, the 1999 ICR 

demonstrated that numerous EGUs have 

conducted trial burns and gained 

sufficient experience such that co-firing 

blends of various coal ranks is now 

common practice. In fact, the EPA 

believes that such blends may be 

modified daily, depending on the 

characteristics of the coal being burned 

and on the level of generation needed. 

The extent of blending, and the ability 

to switch the blends on short notice, 

does not lend itself (or, in fact, argue 

for) additional subcategorization. 

The EPA disagrees with any assertion 

that the EPA ignored possible 

subcategorization approaches or that it 

has insufficient data upon which to base 

or evaluate various subcategories. The 

EPA fully examined the record, which 

demonstrates that coal-fired EGUs, with 

the exception of certain units for Hg, 

have similar HAP emissions profiles 

and that similar control approaches are 

available to such EGUs. Although 

commenters suggested additional 

subcategories were warranted, they 

failed to provide sufficient data to 

support their proposed alternative 

subcategories. As noted elsewhere, the 

EPA does not disagree with commenters 

that there are some differences in EGUs. 

However, the EPA does disagree with 

commenters that those differences result 

in differences in emissions to the 

atmosphere such that additional 

subcategorization is justified. 

Failing to demonstrate that coal-fired 

EGUs are different based on emissions, 

the commenters turn to economic 

arguments, asserting that failing to 

subcategorize will impose an economic 

hardship on certain sources. Congress 

precluded consideration of costs in 

setting MACT floors, and it is not 

appropriate to premise 

subcategorization on costs either. See S. 

Rep No. 101–228 at 166–67 (5 

Legislative History at 8506–07) 

(rejecting the implication that separate 

categories could be based on ‘‘assertions 

of extraordinary economic effects’’); see 

also NRDC v. EPA 489 F.3d 1364 (D.C. 

Cir. 2007) (holding that EPA properly 

declined to create a subcategory for a 

particular source and rejecting the 

argument that the source may have to 

incur more costs to comply with the 

rule without such subcategory). 

The final limits are based on EGUs 

currently operating with available 

controls. As noted above, the record 

shows that the various types of EGUs 

are represented in the floors, with the 

exception of certain units for Hg, which 


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indicates that the levels are achievable 

by such units. Thus, the data actually 

show that the MACT standards are 

achievable for a wide variety of EGUs. 

In addition, the EPA believes it has 

fulfilled the CAA section 112(c)(l) 

directive that ‘‘[t]o the extent 

practicable, the categories and 

subcategories listed under this 

subsection shall be consistent * * *’’ 

with those of CAA section 111, 

notwithstanding commenters assertion 

to the contrary. The decision on 

whether to directly align CAA sections 

112 and 111 subcategories is 

discretionary and EPA has reasonably 

exercised its discretion in declining to 

create additional subcategories for coalfired EGUs based on the record, with the 

exception of certain sources for Hg. 

Finally, the EPA disagrees with the 

commenters that suggest that EPA lacks 

the legal authority to consider material 

inputs when considering subcategories. 

We agree, however, that material inputs 

must be considered when establishing 

MACT standards for the subcategories 

that are established. We also believe a 

meaningful consideration of fuel 

switching can occur even if sources are 

subcategorized based on fuel inputs 

because EPA 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 rank virgin coal 

subcategory for Hg are also present in 

the high sulfur or high chlorine coal 

context. The commenter stated that the 

data indicate that even 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 

absent such a subcategory, about 12 

percent of coal deliveries (2005 data), 

and the vast majority of coal shipped 

from the states of Indiana, Ohio, and 

Illinois (2008 data), would become 

unusable. The commenter expressed 

support for the alternative SO2 standard 

for units unable to meet the HCl 

standard; however, the commenter also 

believed that it is appropriate to 

establish a coal chlorine or sulfur 

content-based subcategory for the 

alternative SO2 standard. The 

commenter stated that coal testing data 

indicate a clear break in chlorine 

concentrations in the coals burned by 

EGUs, as well as in sulfur content. The 

commenter indicated that there are 

factors supporting a high sulfur or high 

chlorine coal subcategory that are 

similar to those that the EPA relied 

upon to support a Hg subcategory for 

low rank virgin coal. According to the 

commenter, the EPA’s key rationale for 

a Hg subcategory for low rank virgin 

coal was that no low rank virgin coalfired unit appeared in the ‘‘top 

performing 12 percent of sources, 

indicating a difference in the emissions 

for this HAP from these types of units.’’ 

The EPA did not establish other 

subcategories because ‘‘the data did not 

show any difference in the level of HAP 

emissions and, therefore, we have 

determined that it is not reasonable to 

establish separate emissions limits for 

other HAP.’’ The commenter indicated 

that the EPA does not need emissions 

data to know that even well-controlled 

units burning higher sulfur coals would 

be unable to meet the alternative SO2

emissions rate, and would therefore also 

not appear in the top 12 percent of 

performing units. 

Response: The EPA disagrees with 

commenters that subcategories should 

be established for high sulfur and high 

chlorine coals. It appears from the 

comments that it is not in fact the 

chlorine content that is at issue but the 

sulfur content of the coal. Commenters 

state that they are unable to meet the 

HCl limit, but they only provide 

information indicating it would be 

difficult to meet the alternative 

equivalent SO2 limit. In fact, our data 

show that coals with chloride contents 

as high as 2,100 ppm (0.16 lb/MMBtu) 

were burned by EGUs making up the 

MACT floor pool of sources for the final 

HCl emission limit and that the bestperforming unit was burning coal with 

a maximum chloride content of 1,200 

ppm. The median chloride level for 

bituminous coals identified from data 

submitted through the 1999 ICR was 

1,030 ppm so we believe that the coals 

represented in the MACT floor pool 

indicate that the final limits are 

achievable with high-chlorine coals. We 

have determined that HCl removal is 

very effective using a number of 

different types of FGD systems. Absent 

information demonstrating that sources 

are unable to meet the proposed HCl 

limit due to the chlorine content of the 

coal, we believe it is unnecessary and 

inappropriate to consider 

subcategorizing based on chlorine 

content in the coal. 

In addition, as noted above, the SO2

limit is an alternative equivalent 

standard that is available to sources that 

have an SO2 control and CEMS and 

operate the controls at all times. The 

EPA did not provide the alternative 

equivalent standard for sources that 

could not meet the HCl limit as one 

commenter suggests; instead, we 

provided the standard as a convenience 

and cost saving measure to EGUs with 

installed FGD systems because we 

recognize that many EGUs have SO2

CEMS. Sources are required to comply 

with the HCl limit as a surrogate for all 

the acid gas HAP or the SO2 limit as an 

alternate equivalent standard. 

Commenters have not demonstrated that 

they are unable to meet the HCl 

standard and our data show that the 

standard is achievable even for high 

chlorine coals. 

Comment: Several commenters 

supported the development of a separate 

subcategory for fluidized bed 

combustors (FBC) or circulating 

fluidized bed (CFB) EGUs. The 

commenters encouraged the Agency to 

consider subcategorization of FBC EGUs 

for Hg emissions noting that the 

industry has long contended that the 

design, construction, and operation of 

FBCs are different than conventional 

boilers and that FBCs employ 

fundamentally different processes than 

conventional PC-fired EGUs. The 

selection of an FBC unit over a 

conventional PC boiler is driven in large 

part by fuel characteristics. The 

commenters assert that, as a result, the 

emissions profile of FBC units generally 

differ from conventional PC boilers 

because FBC units more advantageously 

combust waste coals, as well as coal 

blends with other carbonaceous 

material. The commenters stated that 

the EPA did not discuss the design 

differences between FBC units and PC 

units in the preamble to this proposed 

rule unlike what the Agency did when 

it previously proposed Hg MACT limits 

in January 2004. Commenters state that, 

for these reasons, FBC units can be 

considered a distinct type of boiler. 

The commenters noted that an 

examination of the 40 ‘‘best performing’’ 

units for Hg emissions in the proposed 

MACT floor spreadsheet showed that 14 

of those units are FBC units. The 

commenters maintained that had FBC 

units performed as well as conventional 

PC boilers, 2 units would have been 

expected to be in the top 40. The 

commenters allege that the far higher 

percentage of FBCs in the top 40 leads 

to the conclusion that these units are 

different from conventional PCs with 

regard to Hg emissions and, as a result, 

should have been placed in their own 

subcategory. Further, commenters noted 

that the largest FBC has a nameplate 

capacity of about 300 MW while the 

largest conventional boilers have 

nameplate capacities of around 1,300 

MW. 

The commenters stated that FBCs 

combust relatively large coal particles in 

a bed of sorbent or inert material at a 

lower degree of combustion efficiency. 


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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. 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 PCfired EGUs and FBC/CFB EGUS; 

however, the commenters are incorrect 

in asserting that the HAP emissions 

levels and characteristics are 

sufficiently distinct from other coalfired EGUs to support subcategorization. 

Further, commenters fail to note that 

FBC EGUs were not subcategorized in 

CAMR even though, as commenters 

note, such design and operation 

differences were cited there. The fact 

that FBC units operate at lower 

temperatures is of no consequence as 

they still operate at temperatures high 

enough to vaporize Hg. 

Commenters assert that FBC units are 

disproportionately represented among 

the best performers, with the inference 

being that they were selected to test in 

the 2010 ICR because of their boiler 

design. However, FBC EGUs were not 

specifically selected as best performers 

for Hg, as EPA did not select any EGUs 

based on a determination that they were 

best performers for Hg (as noted 

elsewhere, we had no basis for selecting 

EGUs as being best performers for Hg), 

and to the extent CFB units were 

selected in the 2010 ICR, they were 

selected because we determined they 

were best performers for non-mercury 

metallic HAP, acid gas HAP, or organic 

HAP or because they were randomly 

selected among the non-best performers 

for those three HAP groupings. Thus, 

the CFBs were selected for testing under 

the 2010 ICR based not on their boiler 

design but, rather, based on the age and 

on their PM and FGD control systems 

(as noted in the Supporting Statement 

for the 2010 ICR). As many FBC EGUs, 

including CFB EGUs, are relatively new, 

they were included in the non-mercury 

metallic HAP group selected for testing 

(because their PM controls were among 

the 175 newest), the acid gas HAP group 

selected for testing (because FBC was 

considered to be an FGD system and the 

units were among the 175 newest), and 

organic HAP testing (because they were 

among the newest and, thus, determined 

to be among the most efficient). 

The effect on Hg emissions is not 

what commenters suggest because, 

although, as noted by commenters, FBC 

units may be found among the better 

performers (among the top 10 EGUs) on 

the Hg MACT floor spreadsheet, they 

are also found in the range of 221 to 226 

EGUs (of 393 data points). The fact that 

FBC units have ‘‘vastly dissimilar ash 

properties’’ that may contain higher 

levels of lime or unburned carbon in the 

fly ash than conventional PC EGUs does 

not indicate that the overall system 

behaves any differently with regard to 

emissions to the atmosphere (the key 

metric) than a conventional PC EGU 

with add-on 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 EGUs of all types are currently 

meeting one or more of the final 

standards. Thus, the EPA finds no basis 

for subcategorizing FBC EGUs. 

Further, as noted below, the EPA does 

not believe there is a basis for 

subcategorizing small EGUs, either FBC 

or PC. In addition, the data have been 

re-evaluated based on comments 

received and an FBC unit is not the 

basis for the new source Hg MACT floor. 

Comment: Many commenters stated 

that the EPA should have considered 

additional subcategorization schemes, 

including one based on EGU size. 

Commenters noted that one of the 

factors that the Administrator can 

consider under CAA section 112(d)(1) in 

making subcategorization decisions is 

unit size. Commenters stated that an 

analysis of the 2010 ICR data showed a 

statistical difference between EGUs with 

a capacity of 100 MW or less and EGUs 

above 100 MW; other commenters 

suggested that the cut-off range should 

be 125 MW. Although large in number 

(about 27 percent) of all EGUs, these 

small EGUs only comprise about 5 

percent of the coal-fired capacity in the 

U.S. Thus, commenters assert that if 

different MACT limits are set for this 

subcategory of EGUs, it will not have a 

significant impact on the health effects 

of HAP emissions. Commenters noted 

that although emission rates from such 

small EGUs are greater than those found 

in the large unit fleet, their contribution 

to the total EGU emissions is not 

significant. The costs associated with 

coming into compliance with the 

proposed rule by installing new controls 

would be proportionally much higher 

for these small EGUs than larger EGUs 

according to the commenters. The 

commenters allege that this would force 

the retirement of generation capacity 

and threaten electrical reliability 

without appreciable benefit to the 

environment. 

One commenter stated that in general, 

the nature of many public power 

facilities differs from the general 

population of coal-fired power plants. 

Public power units tend to be smaller 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, 


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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 

small- and medium-sized public power 

utilities. In particular, the EPA did not 

avail itself of the opportunity to use a 

public power electric utility 

subcategory, rural subcategory, or fuel 

type subcategories. Other commenters 

endorsed the establishment of a less 

than 100 MW subcategory that would 

reduce the costs of the proposed rule 

significantly, but only affect 5 percent of 

the total electric utility sector, and help 

minimize retirement of uneconomical 

plants. 

One commenter stated that the EPA 

properly recognized that subcategories 

based on unit size would be 

inappropriate because the proposed 

emission limits are in terms of lb/ 

MMBtu or lb/TBtu and noting that an 

EGU’s total nameplate capacity is 

wholly unrelated to its ability to achieve 

the proposed limits. Another 

commenter opposed any proposal to 

subcategorize units below 100 MW. The 

proposed rule does not apply to units 

less than or equal to 25 MW, and this 

commenter believed that this is a 

sufficient threshold for applicability. 

One commenter stated that the EPA 

could establish subcategories for the 

purpose of temporarily exempting, for 

example, a subcategory of utilities that 

meet the definition of small entity for 

purposes of the proposed rule. The 

temporary exemption would sunset on a 

date certain (e.g., 3 years from the 

effective date of the rule) at which point 

the sources in the subcategory would 

become subject to the rule, and a 

compliance timetable would start to 

run. The commenter believed that this 

time-staged promulgation and 

compliance proposal would greatly 

increase the chance that the control 

measures could be added in an orderly 

and efficient manner with minimal 

disruption to power markets and grid 

reliability. 

Response: The EPA agrees with 

commenters who stated that an EGU’s 

size is totally unrelated to its ability to 

comply with the final concentrationbased 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 on a 

30-boiler operating day rolling average, 

a level more stringent than that 

developed for the >8,300 Btu 

subcategory as a whole. We do not 

believe that this is what commenters 

envisioned when suggesting such a 

subcategory but we believe it confirms 

our analysis of the data that indicates, 

as noted, these units are controlled in 

the same manner as other, larger EGUs, 

such that additional subcategorization is 

not necessary or reasonable. Further, 

based on the number of EGUs less than 

125 MW in the HCl and PM MACT floor 

pools, we believe that a similar analysis 

for HCl and PM would lead to similar 

or more stringent standards than 

without the additional subcategory. 

Thus, units of all sizes are capable of 

achieving the proposed limits and the 

EPA is not finalizing a subcategory 

based on unit size in the final rule. 

The CAA authorizes EPA to 

subcategorize based on ‘‘classes, types, 

and sizes of sources.’’ The EPA does not 

believe that this provision permits 

subcategorizing sources based solely on 

their status as small entities for several 

reasons. As a threshold matter, 

commenters provided no information to 

suggest that EGUs at small entities are 

different from EGUs owned by other 

entities. Instead, the commenters’ 

justification for such a subcategory was 

that the costs to comply with the 

standards make it more difficult for 

small entities; thus, the basis is 

essentially a cost basis and we do not 

think that is consistent with the statute. 

Moreover, the legislative history of CAA 

section 112(d) supports EPA’s 

interpretation that subcategories cannot 

be based on the cost of compliance. See 

S. Rep No. 101–228 at 166–67 (5 

Legislative History at 8506–07) 

(rejecting the implication that separate 

categories could be based on ‘‘assertions 

of extraordinary economic effects’’). 

In addition, the EGUs owned by small 

entities use the same type of fuel as 

other units, have the same type of 

combustor designs, and can use the 

same types of controls, and so there is 

no difference in the HAP emissions 

from such units. So, even if we believed 

a subcategory based on small entities 

was consistent with the statute, we 

would decline to include such a 

subcategory. 

Therefore, given the language of CAA 

section 112(d), the legislative history, 

and the available information, EPA is 

not creating a separate subcategory for 

EGUs owned by small entities. 

In addition, the D.C. Circuit has 

clearly stated that the EPA does not 

have the statutory authority under CAA 

section 112 to extend compliance dates 

past the 3-year maximum compliance 

time authorized in CAA section 

112(i)(3)(A) except consistent with CAA 

sections 112(i)(3)(B) and 112(i)(4). See 

NRDC v. EPA, 489 F.3d 1364, 1374 (D.C. 

Cir. 2007) (finding that ‘‘Congress 

enumerated specific exceptions to the 3- 

year maximum, which indicates that 

Congress has spoken on the question 

and has not provided the EPA with 

authority under subsection 112(i)(3)(B) 

to extend the compliance date * * *’’) 

(citing also CAA section 112(i)(4)). The 

EPA may not alter the compliance date 

based on size or ownership 

considerations and, thus, we are not 

providing a separate compliance date 

for different groups of EGUs in the final 

rule. 

Comment: One commenter stated that 

the EPA should establish a subcategory 

consisting of EGUs that had received air 

construction permits but had not yet 

commenced construction as of the date 

of the EPA’s proposed rule. The 

commenter believed that such a 

category would be justified because a 

substantial amount of time, money, and 

effort has been invested in these units. 

The commenter asserted that imposing 

new source standards on these EGUs for 

which the EPA’s proposed rule had not 

been anticipated during their permit 

consideration would unreasonably and 

arbitrarily impose additional costs and 

burdens on these projects and would 

likely threaten the viability of many of 

them. The standards for this subcategory 

would be based on the anticipated 

performance of these units (as reflected 

by the permitted case-by-case emission 

levels), ensuring a reasonable and 

appropriate level of HAP control 

without unreasonably and arbitrarily 

interfering with the development of 

these units. 

Response: Clean Air Act section 

112(a)(4) defines a new source as ‘‘a 

stationary source the construction or 

reconstruction of which is commenced 

after the Administrator first proposes 

regulations under this section 

establishing an emission standard 

applicable to such source.’’ The EPA’s 

regulations implementing the CAA 

section 112 General Provisions define 

‘‘commenced’’ to mean ‘‘with respect to 

construction or reconstruction of an 


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affected source, that an owner or 

operator has undertaken a continuous 

program of construction or 

reconstruction or that an owner or 

operator has entered into a contractual 

obligation to undertake and complete, 

within a reasonable time, a continuous 

program of construction or 

reconstruction.’’ See 40 CFR 63.2. 

The EPA is constrained by the 

definition of ‘‘new source’’ such that 

any source that ‘‘commenced’’ 

construction after the May 3, 2011, 

proposal date is considered a new 

source under the statute and the source 

must comply with the new source 

standards even if the source received a 

final and legally effective CAA section 

112(g) permit before proposal. It is 

unclear from the comments whether the 

sources identified in the comments have 

commenced construction as defined in 

the regulations; however, the identified 

sources are existing sources, not new 

sources, under the final rule if 

construction was commenced prior to 

the proposal date. 

Under the final rule, new sources 

must comply with the standards on the 

date of promulgation or at startup, 

whichever is earlier, and existing 

sources have 3 years to come into 

compliance with the final standards. 

Pursuant to the EPA’s regulations at 40 

CFR 63.44(b)(1), however, we may 

provide in a final CAA section 112(d) 

standard a specific compliance date for 

those sources that obtained a final and 

legally effective CAA section 112(g) 

case-by-case MACT standard and 

submitted the information required by 

40 CFR 63.43 to the Agency before the 

close of the comment period. The EPA 

does not believe it has received such 

information during the comment period 

and we are not establishing a separate 

specific compliance period for sources 

that obtained final and legally effective 

CAA section 112(g) standards prior to 

promulgation of the final rule. In the 

absence of EPA action on this issue, 

state Title V permitting authorities are 

required to ‘‘establish a compliance date 

in the [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-togovernment relationship of the Navajo 

Nation and the U.S. government, and 

consistent with the right of sovereignty 

and self-determination of the Navajo 

Nation, it may be appropriate to classify 

EGUs on tribal lands in a different 

subcategory from those on non-Indian 

lands. The commenter stated that in 

accordance with the distinctive status of 

Indian lands, based on principles of 

tribal sovereignty and selfdetermination, the government-togovernment relationship, and the 

flexibility of federal agencies mandated 

under E.O. 13175, the EPA should 

classify sources on tribal lands as a 

unique subcategory of EGUs for which 

emission standards for NESHAP should 

be set pursuant to CAA section 

112(d)(3). 

Response: Pursuant to CAA section 

112(d)(1), the EPA may subcategorize 

sources based on differences in class, 

type, or size. In the preamble to the 

proposed rule, the EPA further explains 

that any basis for subcategorizing (e.g., 

class) must be related to an effect on 

emissions, rather than some difference 

which does not affect emissions 

performance. The EPA does not agree 

that a subcategory based on location on 

Tribal lands is consistent with the 

statutory authority to subcategorize, and 

commenters do not explain why 

emissions would be different for EGUs 

located on Tribal lands. Absent that 

showing, EPA believes it would not be 

appropriate to subcategorize units even 

if we believed such a subcategory is 

consistent with the statute. CAA section 

112 imposes specific requirements with 

respect to the methodology that the EPA 

must use in establishing emission 

standards for HAP, including Hg 

emissions from EGUs. Pursuant to CAA 

section 112(d)(1), the EPA may 

subcategorize sources based on 

differences in class, type, or size. The 

EPA believes, that any basis for 

subcategorizing (e.g., class) must be 

related to an effect on emissions, rather 

than some difference which does not 

affect emissions performance. 

However, the EPA is sensitive to the 

commenters’ concerns and particularly 

recognizes the significance of Navajo 

Generating Station to the Central 

Arizona Project and the water delivery 

to tribes. As a result, EPA has been 

consulting with affected Indian tribes 

and working closely with other federal 

agencies, including the Department of 

the Interior, on these issues and intends 

to work with tribal and other authorities 

to ensure a smooth transition and 

address specific issues as they arise. 

2. Oil Subcategories 

Comment: Several commenters stated 

that distillate oil, and in particular ultralow 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 oilfired EGUs into two subcategories 

(distillate and residual oil) would be 

consistent with the discussion of 

subcategory differentiation in the rule’s 

preamble which indicates that the 

division of a category into subcategories 

is justified if the two subcategories have 

very different emissions, which is true 

for distillate vs. residual oils. Distillate 

and residual oils are also differentiated 

by their operating requirements. Some 

commenters stated that as a 

consequence of the mechanical 

differences between boilers 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 oilfired units that distinguish between 

residual and distilled oil would render 

the standards more achievable for 

distinct subcategories of EGUs and 

reduce the number of potential plant 

closures while still advancing the goal 

of reducing overall emissions. These 

commenters contend that MACT floors 

should not be used to eliminate whole 

classes of existing EGUs through 

mathematical floor calculations based 

on data from uncontrolled units and 

combining boiler subcategories that are 

not capable of accommodating a 

different fuel. 

One commenter stated that the EPA 

should not subcategorize 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 


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distinction among units burning 

different grades of liquid oil affects the 

nature or characteristics of emissions in 

a way that impacts the availability of 

controls. According to the commenter, 

both distillate and residual oil-fired 

units can apply similar control 

technologies to reduce HAP emissions, 

and EGUs firing these fuels do not have 

physical distinctions that prevent 

controls from operating effectively. The 

commenter believes that fuel switching 

is an appropriate control technology and 

is available for liquid oil-fired sources. 

Residual fuel oil contains higher levels 

of contaminants, including HAP, than 

distillate oil, and because a regulated 

entity can readily burn cleaner distillate 

oil in lieu of residual oil, it is 

inappropriate to subcategorize based on 

the distillation fraction of the liquid oil. 

Thus, according to the commenter, the 

grade of liquid-oil fuel does not provide 

a reasonable basis for subcategorizing 

various groups of liquid oil-fired EGUs. 

Another commenter alleges that the EPA 

did not list distillate oil-fired EGUs in 

the 2000 Finding. 

Response: The EPA has reviewed the 

data and determined that it is not 

necessary to subcategorize distillate vs. 

residual oil. Commenters had noted that 

the EPA’s MACT Floor Analysis 

spreadsheet at proposal had erroneously 

assigned the oil type used during testing 

for some boilers. The EPA reviewed the 

data and determined that the submitting 

companies had entered the data 

incorrectly, or had indicated that two 

types of oil were fired in different parts 

of the 2010 ICR responses. The EPA 

contacted all of the companies with oilfired EGUs in the 2010 ICR to confirm 

the oil used during testing. Upon review 

of these data, it became apparent that 

units using residual oil with ESPs or 

distillate oil without control were the 

best-performing oil-fired EGUs for PM 

and the HAP metals. Further, although 

emissions of HAP from distillate oilfired EGUs are generally lower than 

those from residual oil-fired EGUs, 

EGUs burning distillate oil appeared to 

have higher emissions of some HAP but 

lower emissions of others. 

In addition, the EPA does not agree 

that distillate oil-fired EGUs were not 

listed in the 2000 Finding. We believe 

it is inappropriate to exclude distillate 

oil-fired EGUs from regulation under the 

final rule because the Agency did not 

make a distinction when listing the oilfired 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 

technology-forcing statute, and, because 

both distillate oil- and residual oil-fired 

EGUs were among the best performing 

sources in the floor and both types are 

meeting the final standards, we cannot 

reasonably conclude that the HAP 

emissions characteristics of these 

similar types of units are distinct. 

Therefore, the EPA is not establishing 

separate subcategories for distillate and 

residual oil-fired units in the final rule. 

3. Limited-Use Subcategory 

Comment: Several commenters stated 

that EPA should establish a 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 cofiring capability to respond to 

unplanned, emergency scenarios by 

operating on oil during required 

minimum oil burn periods, typically 25 

percent oil/75 percent natural gas. The 

commenter noted that operation using 

oil at other times or on 100 percent oil 

during reliability operation periods 

occurs very infrequently; with natural 

gas expected to become more available 

in future years, such an operating 

scenario will become less likely. 

However, while the reliability rules 

remain in place and commenter’s 

boilers are required to operate under his 

regimen, the commenter believed that it 

is essential that it be able to do so. 

Other commenters noted that 

requiring installation of 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 stacktesting at such units would be equally 

impractical and, in addition, would 

likely require the unit to operate on oil 

(and emit HAP just for the test) when it 

would otherwise be off-line or operating 

on natural gas. 

Response: As stated above, after 

considering comments received, we are 

establishing a limited-use subcategory 

for liquid oil-fired EGUs with an annual 

fired capacity factor of less than 8 

percent averaged over each 24-month 

block period after the compliance date. 

At proposal, we solicited comment on 

establishing a limited-use subcategory 

for liquid oil-fired EGUs: 

EPA is also considering a limited-use 

subcategory to account for liquid oil-fired 

units that only operate a limited amount of 

time per year on oil and are inoperative the 

remainder of the year. Such units could have 

specific emission limitations, reduced 

monitoring requirements (limited operation 

may preclude the ability to conduct stack 

testing), or be held to the same emission 

limitations (which could be met through fuel 

sampling) as other liquid oil-fired units. EPA 

solicits comment on all of these proposed 

subcategorization approaches. 

As stated above, the EPA did not have 

sufficient information on limited-use 

liquid oil-fired EGUs upon which to 

base a subcategory at proposal. Some 

sources required to test under the ICR 

did not submit the data until after 

proposal. Commenters indicated that 

their units are different because many of 

them are only called to service to 

address reliability issues associated 

with, for example, natural gas 

curtailments. The commenters further 

indicated that their units are different 

because of the generally infrequent use 

and the sporadic, and at times frequent, 

start-up and shutdown periods (e.g., 

they are often only required to run for 

a couple of hours). These factors would 

lead to differences in the emissions 

characteristics for these units such that 

a numeric standard based on base load 

units would not likely be achievable 

during the very limited times that these 

limited use oil-fired units operate. 

Based on comments received and our 

own analysis, we are finalizing a 

subcategory for limited-use liquid oilVerDate Mar<15>2010 22:15 Feb 15, 2012 Jkt 226001 PO 00000 Frm 00098 Fmt 4701 Sfmt 4700 E:\FR\FM\16FER2.SGM 16FER2

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320Units that co-fire oil and natural gas where the 

oil combustion comprises 10 percent or less of the 

capacity factor are natural gas-fired EGUs that are 

not subject to this final rule. 

fired EGUs as indicated elsewhere in 

this preamble. We find that these units 

constitute a different class and type of 

units because they are generally only 

used to address reliability issues 

associated with, for example, natural gas 

curtailments, and because they in fact 

only run for very limited periods in a 

year on a seasonal basis. 

Although some commenters indicated 

a prevalence of natural gas/oil co-fired 

EGUs, the EPA also understands that 

there are other liquid oil-fired EGUs that 

do not co-fire natural gas but that could 

be subject to mandatory operation 

during periods of natural gas 

curtailment in their operating area if 

sufficient non-natural gas capacity is not 

available. Based on a review of units 

that report oil use to EPA, in 2010 there 

were 228 liquid oil-fired EGUs with a 

capacity factor of less than 5 percent 

and an additional 10 units with a 

capacity factor of between 5 percent and 

10 percent. Only 2 of these units have 

capacity factors between 5 percent and 

8 percent. This subcategory applies only 

to oil-fired EGUs that operate on oil 

alone and act as peaking units, as they 

generally address reliability issues. We 

are establishing the capacity factor 

threshold of 8 percent averaged over 

each 24-month block period after the 

compliance date.320 In addition, as 

discussed below, we are establishing 

work practice standard for this 

subcategory in lieu of numeric emission 

standards. 

Commenters that requested a 

subcategory for these units noted the 

dichotomy of establishing a NESHAP to 

reduce emissions of HAP to the 

environment while at the same time 

requiring an EGU to run for the sole 

purpose of conducting emissions testing 

and thereby emitting those same HAP. 

Because the operation of these units is 

infrequent and unpredictable, 

performing testing to demonstrate that 

emission limits are being met requires 

the sources to be scheduled to be 

operated merely for the purpose of 

performing testing. We realize that 

similar situations occurred in the 

gathering of emissions data through the 

2010 ICR. However, unlike the case of 

one-time testing on a limited number of 

these units, such testing would be 

mandatory on a yearly basis for all of 

the EGUs upon the effective date of the 

final rule. Because requiring testing 

under this rule would in many cases 

require operators of these EGUs to 

schedule operation of these EGUs at 

times they would not otherwise run, it 

would result in both extra cost related 

to the testing as well as extra emissions; 

therefore, the Agency believes that it is 

technically and economically 

impracticable to monitor emissions for 

these EGUs, and that they should be 

subject to work practice standards that 

would not require emissions 

monitoring. 

The annual average capacity factor 

would be calculated on a 24-month 

block period, commencing with the 

compliance date of the final rule. For 

example, assuming a March 1, 2015, 

compliance date, the first 24-month 

block would commence on March 1, 

2015, and end on February 28, 2017, 

with the next 24-month block averaging 

period commencing on March 1, 2017. 

We believe the 24-month averaging 

period is reasonable to account for the 

fact that units needed to address 

reliability issues (e.g., natural gas 

curtailment periods) will be called to 

service sporadically. A 24-month 

averaging period provides flexibility to 

ensure that these units can run if there 

are large periods when natural gas is 

unavailable. As explained above, the 

data shows that most of these units 

operate for less than 8 percent of the 

time, and in fact it is usually less than 

5 percent. Therefore, when considering 

whether these units would be able to 

perform stack testing, in many cases this 

will be for units that in fact operate 

significantly less than 8 percent of the 

time. In these cases, the EPA does not 

want to require the units to operate 

more just for the purpose of running a 

stack test resulting in additional 

pollution and cost. With projections for 

rising oil prices relative to natural gas 

prices, we expect this trend to continue. 

Liquid oil-fired EGUs subject to this 

subcategory would be required to 

conduct the same initial and periodic 

tune-up as all other affected units, but 

would have no other emission limit or 

work practice requirements. 

Although the EPA believes that the 

ability to burn oil up to 8 percent of the 

time should address concerns about 

units that may need to operate using oil 

during gas curtailments. The EPA 

recognizes that if there were a period 

where gas use was more severely 

limited, such units might need the 

flexibility to operate for more than 8 

percent in one year and less in the next, 

which is why we are providing the 2- 

year period; however based on the data 

we do not think EGUs in this 

subcategory will exceed even the 5 

percent capacity factor that the data 

indicate is the average level for these 

sources. 

4. Non-Continental Units 

Comment: Commenters from affected 

island EGUs requested that noncontinental 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. 

Non-continental 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. 

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 noncontinental EGUs warrant a separate 

subcategory for these units and the data 

show that the difference in location 

causes a difference in emissions 

apparently due to the fuel that is 

available for such units; thus, the 

Agency has included such a subcategory 

in the final rule. At proposal, the EPA 

did not have all of the data from liquid 

oil-fired units in non-continental areas 

(e.g., Guam, Puerto Rico) and solicited 

comment on whether a subcategory 

should be established, based on the data 

to be received, for non-continental oilfired 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 


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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 non-continental 

refineries, including a limited ability to 

obtain alternative fuels that lead to 

different emissions characteristics, 

warrant a separate subcategory for these 

EGUs. The EPA believes that units in 

this subcategory will comply through 

the use of cleaner oils or, for PM, 

through the installation of an ESP. The 

EPA finds no merit in the comment that 

Alaska should be included in this noncontinental subcategory because utilities 

in Alaska are not faced with the same 

access issues affecting island-based 

facilities. 

C. Surrogacy 

1. Filterable PM vs. Total PM 

Comment: Numerous commenters 

strongly objected to the use of total PM 

as the surrogate standard for nonmercury HAP metals. They argued that 

filterable PM is a better surrogate, 

especially given EPA’s intent to use a 

PM CEMS for continuous compliance 

demonstration. Other commenters 

argued that we should not use a 

surrogate and instead should require 

direct compliance with a non-mercury 

HAP metals standard. 

Response: We have decided to use a 

filterable PM limit for the PM surrogate 

emission limit in the final rule. 

Although the objective of the 

emission limits we are establishing is to 

reduce the risks associated with HAP 

emissions, the limits are based in part 

upon the demonstrated capabilities of 

control technologies which are installed 

on existing sources. Except for Hg, the 

best PM controls provide the best 

controls of metal emissions. Emissions 

measurements of either filterable 

particulate, total particulate, individual 

metals, or total metals provide 

comparable indications that the best 

level of control is achieved. We can find 

no significant difference in the 

emissions that would be achieved by 

using any one of these emissions 

measurements. 

We re-assessed the relationships 

between individual metal emissions, 

filterable PM emissions, total PM 

emissions, and total PM2.5 emissions 

based on the test results provided 

through part III of the 2010 ICR. We 

compared the measured emissions of 

metals and PM with the uncontrolled 

emissions estimates and found that 

control of PM was indicative of the 

control of metals emissions. In addition, 

we compared the correlations associated 

with non-mercury HAP metal emissions 

and the three forms of PM and found 

that no specific particulate form 

provided a consistently superior 

indicator of better metals control. 

Although control of filterable PM 

provided the best indicator of 

performance for control of some HAP 

metals, control of total particulate or 

total PM2.5 was nearly as good as an 

indicator. For control of other HAP 

metals, total PM measurement provided 

the best indicator of control 

performance because it included the 

vapor-phase metal HAP, although, 

measurement of the control of filterable 

particulate was nearly as good an 

indicator. In addition, certain data 

analyzed by our Office of Research and 

Development indicate that a vaporphase metal, such as Se, can be present 

as an acid gas and reduced significantly 

using acid gas technologies (wet and dry 

scrubbing). Given that the rule also 

provides for acid gas control 

monitoring, and the general equivalency 

of the different indicators, we have 

concluded that use of a filterable PM 

limit as the PM surrogate emission limit 

is appropriate. 

2. Moisture Content of Oil 

Comment: A number of commenters 

stated that studies suggest that chloride 

in fuel oil can result from contamination 

during transportation and processing of 

crude oils and then be emitted as HCl 

during combustion. For example, the 

commenters asserted that the chloride 

contamination of crude oils can occur as 

a result of the ballasting of tanker ships 

with seawater. However, the Oil 

Pollution Act of 1990 requires all new 

oil tankers to be double hulled and 

establishes a phase out schedule (by the 

middle of the decade) for existing single 

hulled tankers with un-segregated 

ballasts. Because of the role of seawater 

contamination in introducing 

contaminants into the oil, the 

commenters suggest that the EPA set a 

percent water content limit for fuel oil 

at a level of 1.0 percent, rather than 

setting HCl and HF emissions limits. 

This would encourage handling and 

transport practices to limit salt water 

contamination. One commenter 

recommended a standard of 1.0 percent 

water because several of the lowest HCl 

and HF emitting units currently require 

percent water (or water and sediment) 

specifications between 0.5 percent and 

1.0 percent. 

Response: The EPA is providing the 

alternative compliance assurance 

approaches in the final rule for liquid 

oil-fired EGUs of demonstrating 

compliance through either specific HCl 

or HF measurements or by 

demonstrating that the moisture content 

in the fuel oil remains at a level no more 

than 1.0 percent. 

The EPA is not aware of any FGD 

systems installed on 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 refer to certain studies 

that provide a plausible reason for the 

chloride/fluoride contamination of fuel 

oils. We found this reason persuasive 

and accordingly are providing 

alternative compliance approaches in 

the final rule to demonstrate compliance 

with the acid gas HAP standards. 

Specifically, sources can demonstrate 

compliance through either specific HCl 

or HF measurements or by 

demonstrating that the moisture content 

in the fuel oil remains at a level no more 

than 1.0 percent. 

D. Area Sources 

Comment: Numerous comments were 

received both in support of and in 

opposition to the establishment of 

generally available control technology 

(GACT) standards for area source EGUs. 

Several commenters in opposition to 

area source standards stated that the 

EPA properly established emissions 

limitations based upon the performance 

of all EGUs, rather than distinguishing 

between major sources and area sources. 

The commenters believe that Congress 

did not intend the EPA to distinguish 

between ‘‘major source’’ EGUs and ‘‘area 

source’’ EGUs in determining whether 

and how to regulate EGUs under CAA 

section 112. These commenters 

indicated that differentiating major 

source and area source EGUs for 

purposes of setting emissions standards 

is inappropriate in light of the 2000 

Finding regarding the threat posed by 

the absence of regulation of HAP 

emissions from EGUs. The 2000 Finding 

was based upon studies whose 

conclusions regarding the impacts from 

EGU emissions did not depend upon 

any relevant distinction between major 

source and area source EGUs. The 

commenters note that segregating 

‘‘major source’’ and ‘‘area source’’ EGUs 


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would have the 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 

recently industrial boilers and note that 

GACT controls have been used 

successfully in many other EPA MACT 

rules, including rules for iron & steel 

foundries, electric arc steelmaking, 

coatings operations, clay ceramics 

manufacturing, glass manufacturing, 

and secondary nonferrous metals 

manufacturing, in order to reduce costs 

and regulatory burdens. The 

commenters state that Congress has 

given the EPA the ability to 

subcategorize area sources because of 

their low HAP emissions and low 

potential impact on human health and 

that, contrary to the plain language of 

CAA section 112 and its legislative 

history, the EPA made no attempt in the 

proposed rule to distinguish between 

major sources and area sources for 

purposes of listing or setting standards. 

The commenters indicated that where 

Congress was concerned about the 

health impacts of specific pollutants 

from specific sources, it knew how to 

specify that MACT limits be 

promulgated (e.g., CAA section 

112(c)(6)). The commenters state that 

area source rules would lessen the 

regulatory burden of a CAA section 112 

EGU rule on many small entities 

(arguing that many EGUs owned by 

small public power entities are area 

sources) and that as many as 12 percent 

of the EGU population could qualify as 

area sources. A number of commenters 

pointed out that the small entity 

representatives (SER) on the SBREFA 

panel suggested that the EPA establish 

separate emission standards for EGUs 

located at area sources of HAP and that 

the standards be based on GACT as 

allowed under CAA section 112(d)(5). 

Specifically, the SERs recommended 

that the EPA establish management 

practice standards for area source EGUs. 

Response: The EPA is not establishing 

an area vs. major source distinction in 

the final rule. 

The CAA section 112(a)(8) definition 

of EGU does not distinguish between 

major and area sources, and we 

maintain that EGUs are a single source 

category that contains both major and 

area sources. The EPA proposed to 

regulate five subcategories of EGUs 

without distinguishing between major 

and area sources for purposes of 

establishing the standards for the 

different subcategories. Our approach is 

wholly consistent with the statutory 

definition of EGU and reasonable. 

Nevertheless, the Agency did examine 

whether to set separate standards for 

area source EGUs, because we do not 

believe that the statute prohibits the 

Agency from exercising its discretion to 

establish GACT standards for area 

sources pursuant to CAA section 

112(d)(5) if we determine such 

standards are appropriate. The EPA is 

not required, however, to establish 

GACT standards for area sources, and 

we believe it may even be unreasonable 

to do so under the circumstances we 

identified in the proposed rule as 

supported by the record of this final 

rule. 

At proposal, we determined that it 

was not appropriate to establish 

separate standards for major and area 

source EGUs, and even if we had 

exercised our discretion to set separate 

standards, we would have likely 

declined to exercise our discretion to set 

GACT standards for area source EGUs 

given our appropriate and necessary 

finding and the fact that a potentially 

large number of area source EGUs are in 

fact large well controlled units. 

Some commenters note that there 

could be as many as 12 percent of the 

total population that could be classified 

as area sources. We are not sure of the 

commenters’ point in regard to this 

statement. As to commenters’ 

statements that many of the area sources 

are municipal utilities, our information 

shows that many rather large EGUs (e.g., 

hundreds of MW) are also area sources, 

and the commenters have not provided 

any justification for establishing GACT 

standards for large synthetic area 

sources. 

Commenters did not provide an 

evaluation of the health and 

environmental impacts of the area 

sources and simply presume that the 

risks from such sources are lower, even 

though many of the same commenters 

noted that these smaller EGUs are often 

located in densely populated areas 

where populations are more likely to 

have adverse health effects from the 

HAP emissions. Furthermore, other 

commenters, including some industry 

commenters, noted that the vast 

majority of these potential area sources 

meet the criteria due to the installation 

of emission controls installed to meet 

other requirements. According to these 

commenters, these synthetic area 

sources would likely be able to meet the 

limits of this rulemaking and imposition 

of this rule would not appear to result 

in the installation of additional controls 

in a number of cases. We do not know 

if this assertion is correct but we 

determined approximately 69 coal-fired 

EGUs will be able to meet the existing 

source MACT standards with their 

current control configuration (out of 252 

EGUs that reported data for Hg, PM, and 

HCl in the 2010 ICR). 

Commenters also note that the Agency 

has exercised its discretion in other 

NESHAP rulemakings to establish area 

source limits. Although true, the fact 

that the EPA has established area source 

limits in some source categories is 

irrelevant to similar decisions for 

different source categories. Commenters 

have not shown that the circumstances 

applicable to those other source 

categories are similar to the 

circumstances identified for major and 

area source EGUs (e.g., similar controls, 

similar emission characteristics, large 

number of synthetic minor area 

sources). Further, those other source 

categories are not statutorily defined in 

a manner that includes both area and 

major sources. EGUs are the only source 

category defined in CAA section 112 

and, in establishing the definition of an 

‘‘electric utility steam generating unit’’ 

under CAA section 112(a)(8), Congress 

included in the EGU source category 

both area and major sources. Thus, it is 

reasonable to regulate the EGU category 

in the manner Congress defined the 

category. Commenters have provided no 

legal support for the contention that the 

EPA must regulate area and major 

sources in the same category in separate 

rulemakings, and the EPA has in fact 

regulated both major and area sources in 


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the same rulemaking even absent a 

statutory definition that includes both 

major and area sources. (See National 

Emission Standards for Hazardous Air 

Pollutants From the Portland Cement 

Manufacturing Industry and Standards 

of Performance for Portland Cement 

Plants; 75 FR 54970; September 9, 

2010.) 

The EPA considered the totality of the 

circumstances when determining 

whether to set separate area and major 

source standards for EGUs and also 

considered whether it would be 

reasonable to establish GACT standards 

for areas sources. We reasonably 

considered whether emissions 

characteristics of major and area sources 

are different when determining whether 

to establish GACT standards, 

notwithstanding commenters’ assertion 

that such consideration is not correct. 

That we also consider emission 

characteristics in subcategorization 

decisions is of no consequence for area 

source decisions. Given that the 

statutory definition of EGUs contains 

both major and area sources, it was 

reasonable to evaluate whether there 

were sufficient differences between area 

and major sources when deciding 

whether to exercise our discretion to set 

separate area and major source 

standards. 

In addition, we find commenter’s 

point concerning CAA section 112(c)(6) 

odd because EGUs emit several of the 

CAA section 112(c)(6) HAP (e.g., lead, 

Hg). Although EGUs were exempted 

from that provision, the fact that they 

emit some of the HAP called out for 

MACT control supports our decision to 

not establish GACT standards for any 

EGUs. CAA section 112(d)(5) leaves it to 

the Agency’s discretion to determine 

whether GACT standards should be 

established for area sources, and the 

statute does not require GACT standards 

or even indicate that such standards are 

to be the default regulatory approach for 

area sources. See 76 FR 25021. Instead, 

the statute provides the Agency with 

discretion and we have exercised it 

reasonably in this case. 

Commenters indicate that many EGUs 

owned by small entities are potential 

area sources. However, commenters fail 

to note that there are also EGUs owned 

by small entities that are not potential 

area sources, and, thus, would not 

accrue any ‘‘lessened regulatory 

burden’’ benefit from a decision by the 

EPA to establish area source standards. 

Some commenters state that the EPA’s 

mere assertion that there would be no 

difference between GACT and MACT to 

justify an area source finding does not 

provide sufficient documentation for the 

decision. But EPA did not say there 

would be no difference between MACT 

and GACT. Instead, it stated that it 

would be difficult to make a distinction 

given the similarities between the EGUs 

and major and area source facilities. 

Specifically, as noted by other 

commenters, and observable by a review 

of the MACT Floor Analysis 

spreadsheets, potential area sources 

range in size from units near the CAA 

section 112(a)(8) defined lower size 

limit to units of hundreds of megawatts. 

Further, these larger area source units 

are, for the most part, controlled with 

the full suite of emission control 

technologies available (e.g., fabric 

filters, scrubbers). 

In addition, the data that were 

available in the docket for the proposed 

rule show that there is little difference 

between major and area source EGUs 

individually, and that generally the 

driver for whether a utility facility is a 

major or area source depends on the 

number of EGUs located at a facility 

(almost exclusively one or two EGUs 

located at area sources), not on any 

inherent difference between the EGUs 

themselves. See ‘‘Evaluation of Area 

Source EGUs’’ TSD, Docket EPA–HQ– 

OAR–2009–0234. In fact there are a 

number of EGUs that are quite large that 

are area sources and others that are 

small that are major sources. Id. This is 

the case because the acid gas HAP 

emissions are what drive EGUs to have 

HAP emissions exceeding the major 

source threshold. With a few 

exceptions, the EGUs located at area 

sources have FGD or other acid gas 

controls that reduce the acid gas HAP to 

area source levels. Id. Thus, the majority 

of sources that currently qualify as area 

sources were, in fact, major sources 

prior to installing controls. The 

exceptions are those units that would 

likely be able to achieve the MACT level 

of control for acid gas with minimal use 

of DSI at a reasonable cost. Id. 

In addition, the data show that a 

number of area sources for which we 

have data are high emitters of Hg and 

non-Hg metal HAP. Id. Pursuant to our 

appropriate and necessary finding, these 

HAP pose a significant threat to human 

health. Thus, even were we to 

distinguish between major and area 

sources, which we do not believe is 

appropriate given the similarities 

between such sources, we would still 

decline to set GACT standards, and as 

such we maintain that MACT standards 

are appropriate. Moreover, for acid gas 

HAP, as discussed above, the data 

indicate that the level of control would 

likely be the same even if we did 

establish GACT standards under CAA 

section 112(d)(5). 

We fully evaluated the nature of 

EGUs, and we do not see a basis on 

which to distinguish these sources for 

purposes of setting standards. Thus, we 

maintain that we reasonably exercised 

the discretion afforded the Agency 

under the statute and declined to set 

separate standards for area source EGUs. 

E. Health-Based Emission Limits 

Comment: Many commenters noted 

that in the proposed rule the EPA 

considered whether it was appropriate 

to exercise its discretionary authority to 

establish health-based emission limits 

(HBEL) under CAA section 112(d)(4) for 

HCl and other acid gases and proposed 

not to adopt such limits, citing, among 

other things, information gaps regarding 

facility-specific emissions of acid gases, 

co-located sources of acid gases and 

their cumulative impacts, potential 

environmental impacts of acid gases, 

and the significant co-benefits estimated 

from the adoption of the conventional 

MACT standard. Comments were 

received both supporting this position 

and refuting it. Several commenters 

suggested legal, regulatory and scientific 

reasons for why HBEL for HCl might be 

appropriate for this MACT standard. 

With respect to legal concerns, some 

commenters indicated that CAA section 

112(d)(4) establishes a mechanism for 

the EPA to exclude facilities from 

certain pollution control regulations and 

circumstances when these facilities can 

demonstrate that emissions do not pose 

a health risk. Commenters cited a Senate 

Report that influenced development of 

CAA section 112(d)(4), where Congress 

recognized that, ‘‘For some pollutants a 

MACT emissions limitation may be far 

more stringent than is necessary to 

protect public health and the 

environment.’’ (Footnote: S. Rep. No. 

101–128 (1990) at 171.) Commenters 

also cited regulatory precedent for 

addressing HCl as a threshold pollutant, 

including the Hazardous Waste 

Combustors and the Chemical Recovery 

Combustion Sources at Kraft, Soda, 

Sulfite, and Stand-Alone Semichemical 

Pulp Mills NESHAP. Commenters 

requested that the EPA incorporate the 

flexibility afforded by CAA section 

112(d)(4) and allow sources reasonable 

means for demonstrating that their 

respective emissions do not warrant 

further control. The commenters also 

cited the 2004 vacated Boiler MACT as 

precedent for HBEL for HCl. The 

commenters contended that the EPA 

failed to explain why the health-based 

emissions limitations it established in 

the 2004 Boiler MACT and the 

justification provided for those 

limitations could not be used in this 

case. The commenters also cited a 2006 


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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 manganese (Mn). These 

commenters argue there are no 

differences sufficient to warrant a 

reversal of that decision in the EGU 

MACT standard. The commenters raised 

concerns that health risk information 

cited by the EPA for HCl, HF, and 

hydrogen cyanide (HCN) does not 

establish ‘‘an ample margin of safety’’ 

and, therefore, no health threshold 

should be established. The commenters 

believe risk-based exemptions at levels 

less stringent than the MACT floor are 

prone to lawsuits that could potentially 

further delay implementation of the 

EGU MACT. 

Some commenters disagreed with 

using a hazard quotient (HQ) approach 

to establish a risk-based standard 

because the HQ would not account for 

potential toxicological interactions. The 

commenter noted that an HQ approach 

incorrectly assumes the different acid 

gases affect health through the same 

health endpoint, rather than assuming 

that the gases interact in an additive 

fashion. This commenter suggested that 

a hazard index approach, as described 

in the EPA’s ‘‘Guideline for the Health 

Risk Assessment of Chemical Mixtures,’’ 

would be more appropriate. 

Some commenters dispute that 

emissions from other EGUs or source 

categories should be considered when 

developing an HBEL and they argued 

that Congress expected the EPA to 

consider the effect of co-located 

facilities during the CAA section 112(f) 

residual risk program instead of under 

CAA section 112(d). Commenters added 

that there is no prior EPA precedent for 

considering co-located facilities from a 

different source category during the 

same CAA section 112 rulemaking. 

Several commenters disputed the 

EPA’s consideration of non-HAP 

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 

technology-based standards for HCl will 

result in significant reductions in the 

emissions of other pollutants, including 

SO2, Hg, and PM. The commenter added 

that these reductions will provide 

enormous health and environmental 

benefits, which would not be 

experienced if CAA section 112(d)(4) 

standards had been finalized. These 

commenters contended that HCl and 

other dangerous acid gases produced by 

EGUs pose substantial risks to industrial 

workers, as well as surrounding 

communities, and must be limited by 

the strict conventional MACT standards. 

Several commenters indicated that the 

current economic climate requires the 

EPA to balance economic and 

environmental interests and indicated 

that HBEL would help target 

investments into solving true health 

threats where limits are no more or less 

stringent than needed to protect public 

health. Many commenters provided 

estimates of compliance cost savings if 

an HBEL is included in this final rule. 

Some commenters stressed the 

importance of an HBEL for small 

entities affected by the regulations. 

Several other commenters suggested 

that the EPA should estimate the costs 

and environmental effects of the HBEL 

option compared to a conventional 

MACT standard in order to make an 

informed decision on the adoption of 

HBEL. 

Response: After considering the 

comments received, the EPA has 

decided not to adopt an emissions 

standard based on its authority under 

CAA section 112(d)(4) for all the reasons 

set forth in the proposed rule. 

The EPA notes that the Agency’s 

authority under CAA section 112(d)(4) 

is discretionary. That provision states 

that the EPA ‘‘may’’ consider 

establishing health thresholds when 

setting emissions standards under CAA 

section 112(d). By the use of the term 

‘‘may,’’ Congress clearly intended to 

allow the EPA to decide not to consider 

a health threshold even for pollutants 

which have an established threshold. As 

explained in the preamble to the 

proposed rule, it is appropriate for the 

EPA to consider relevant factors when 

deciding whether to exercise its 

discretion under CAA section 112(d)(4), 

and, notwithstanding commenters’ 

assertions to the contrary, the 

considerations we include in our 

analysis are reasonable. The EPA has 

considered the public comments 

received and is not adopting an 

emissions standard under CAA section 

112(d)(4) for the reasons set forth in the 

proposed rule and explained below. We 

note that this action is consistent with 

EPA’s recent decisions not to develop 

standards under CAA section 112(d)(4) 

for the Industrial, Commercial and 

Institutional Boilers and Process Heaters 

and the Portland Cement source 

categories. 

As explained in the preamble to the 

proposed rule, the EPA continues to 

believe that the potential cumulative 

public health and environmental effects 

of all acid gas HAP emissions, not just 

HCl emissions, from EGUs and other 

acid gas sources located near EGUs 

supports the Agency’s decision not to 

exercise its discretion under CAA 

section 112(d)(4). Additional data for all 

acid gas emissions were not provided 

during the comment period, and the 

data already in hand regarding these 

emissions are not sufficient to support 

the development of emissions standards 

for EGUs under CAA section 112(d) that 

take into account the health threshold 

for acid gas HAP, particularly given that 

the Act requires the EPA’s consideration 

of health thresholds under CAA section 

112(d)(4) to protect public health with 

an ample margin of safety. We note here 

that EPA agrees with the commenter 

who pointed out that a better way to 

evaluate the potential health impact 

interactions of all acid gases would be 

to use the approach in EPA’s ‘‘Guideline 

for the Health Risk Assessment of 

Chemical Mixtures’’ rather than a 

simple evaluation of individual HQ 

values for each acid gas, but we further 

note that use of such an approach 

requires a substantially greater 

knowledge of acid gas emissions than is 

currently available. We further note 

that, even if cost were a relevant factor 

in setting standards under CAA section 

112(d)(4), since the data are not 

available that would allow us to develop 

an acid gas HBEL appropriate to protect 

public health with an ample margin of 

safety, we cannot determine whether 

such standards would have any cost 

savings associated with them or not. In 

addition, the concerns expressed by the 

EPA in the proposal regarding the 

potential environmental impacts and 

the cumulative impacts of acid gases on 

public health were not assuaged by the 


srobinson on DSK4SPTVN1PROD with RULES2
9406 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

comments received because no 

significant data regarding these impacts 

were received. 

The EPA also received comments 

recommending not only that the EPA 

establish emissions standards for acid 

gases pursuant to CAA section 

112(d)(4), but that it do so by excluding 

specific facilities from complying with 

emissions limits if the facility 

demonstrates that its emissions do not 

pose a health risk. The EPA does not 

believe that a plain reading of the 

statute supports the establishment of 

such an approach. Although CAA 

section 112(d)(4) authorizes the EPA to 

consider the level of the health 

threshold for pollutants which have an 

established threshold, that threshold 

may be considered ‘‘when establishing 

emissions standards under [CAA section 

112(d)].’’ Therefore, the EPA must still 

establish emissions standards under 

CAA section 112(d) even if it chooses to 

exercise its discretion to consider an 

established health threshold. A sourceby-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 rule, the EPA 

also considered the co-benefits of setting 

a conventional MACT standard for HCl. 

The EPA considered the comments 

received on this issue and continues to 

believe that the estimated co-benefits 

are significant and provide an 

additional basis for the Administrator to 

conclude that it is not appropriate to 

exercise her discretion under CAA 

section 112(d)(4). The EPA disagrees 

with the commenters who stated that it 

is not appropriate to consider non-HAP 

benefits in deciding whether to invoke 

CAA section 112(d)(4). Although MACT 

standards may directly regulate only 

HAP and not criteria pollutants, 

Congress did recognize, in the 

legislative history to CAA section 

112(d)(4), that MACT standards would 

have the collateral benefit of controlling 

criteria pollutants as well and viewed 

this as an important benefit of the air 

toxics program. See S. Rep. No. 101– 

228, 101st Cong. 1st sess. at 172. The 

EPA consequently does not accept the 

argument that it cannot consider 

reductions of criteria pollutants in 

determining whether to take or not take 

certain discretionary actions, such as 

whether to adopt an HBEL under CAA 

section 112(d)(4). There appears to be 

no valid reason that, in situations where 

the EPA has discretion in what type of 

standard to adopt, the EPA must ignore 

controls which further the health and 

environmental outcomes at which CAA 

section 112(d) is fundamentally aimed 

because such controls not only reduce 

HAP emissions but emissions of other 

air pollutants as well. Thus, the issue 

being addressed is not whether to 

regulate non-HAP under CAA section 

112(d) or whether to consider other air 

quality benefits in setting CAA section 

112(d)(2) standards—neither of which 

the EPA is doing—but rather whether 

EPA may exercise its discretion to 

regulate certain HAP based on the 

MACT approach and consider collateral 

health and environmental benefits when 

choosing whether to exercise that 

discretion. The EPA believes there is no 

legal principle that precludes it from 

doing so and commenters have not 

provided one. 

F. Compliance Date and Reliability 

Issues 

Comment: Multiple commenters 

asked that the compliance date be 

clearly stated as soon as possible, as 

well as that guidance be provided for 

utilities unable to comply with the 

stated timelines, to allow time for 

utilities to prepare for compliance. 

Commenters also asked that any 

decisions or policies on extensions be 

published in a rulemaking. In addition, 

commenters requested that the EPA 

establish, streamline, and simplify the 

process of applying for the 1-year 

extension under CAA section 112(i)(3). 

Multiple commenters offered 

suggestions on methods for allowing 

more time for compliance, including 

EPA’s authority under CAA section 

112(n)(1)(A); state authority under CAA 

section 112(i)(3); Presidential authority 

under CAA section 112(i)(4); categorical 

extensions for publicly-owned or 

governmental facilities according to EO 

13132, 13563, and UMRA of 1995; statedesigned 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 ‘‘controls’’ under the CAA. 

Commenters noted the specific 

situations related to small entities and 

their inability to compete with the 

larger, investor-owned utilities for 

financing and engineering and technical 

labor as well as the different process 

they need to follow for capital 

improvements. Multiple commenters 

asked that the EPA consider other 

simultaneous rulemakings (e.g., Cooling 

Water Intake Structures; Coal 

Combustion Residuals; CSAPR, etc.) and 

extend the compliance period. Many 

commenters noted these other 

requirements and suggested that 

installation of the necessary controls 

could not be completed within the 

compliance period allowed under CAA 

section 112, even if a fourth year were 

to be granted by the permitting 

authority, citing examples of the times 

necessary for installation of various 

pieces of control equipment or 

replacement power. 

Some commenters pointed to existing 

state programs (e.g., Colorado, Oregon, 

Washington) and indicated that if states 

can demonstrate that overall emissions 

reductions would be equivalent or 

greater than those that would be 

achieved by the proposed rule, the EPA 

should delegate the CAA section 112 

program to these states, even if the state 

emissions reductions would not 

necessarily occur on the same schedule 

(many state programs call for retirement 

of EGUs in years beyond the CAA 

section 112 compliance date). The 

commenters did not want the 

promulgation of the final rule to 

undermine the significant amount of 

work that may have been invested in 

creating state-specific programs to curb 

emissions within a reasonable 

timeframe. The commenters seek to 

make use of temporal flexibility, 

authorized under CAA section 112(i)(3), 

in obtaining delegation of the final rule 

to preserve the hard-negotiated 

comprehensive state-specific programs 

designed to yield greater emission 

reductions than the MATS alone. 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9407 

321The EPA’s analysis also identifies a small 

amount of capacity loss (less than 0.7 GW) due to 

derating of certain units, as well as partially 

offsetting reductions in non-coal retirements in 

comparison with the base case. The net estimated 

reduction in capacity, in comparison with the base 

case, is estimated at less than 5 GW. 

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 well-positioned to comply 

with the EPA’s proposed air regulations 

without threatening electric system 

reliability. Commenters assert that, if 

electric system reliability were to be 

threatened in local areas as a result of 

the rule, the EPA has the statutory 

authority to grant, on a case-by-case 

basis, extensions of time to complete the 

installation of pollution control systems. 

One commenter stated that no 

additional controls would need to be 

installed in many cases and any coal 

unit should be able to comply with all 

of the standards. Another commenter 

noted that utilities that failed to plan 

ahead ‘‘should not be permitted to use 

their own inaction to justify more time.’’ 

Commenters noted that several major 

utility companies have anticipated the 

EPA’s rules and are already taking 

action to ensure a reliable supply of 

electricity in their service territory and 

beyond. Other commenters agree that 

there is significant excess generation 

capacity in the country and reliability 

will not be threatened by the rule. 

According to one commenter, 

companies are already preparing for a 

2015 compliance date, factoring in the 

capital expenditures required to comply 

and delays would undermine decisions 

that have already been made. 

Commenters cite, for example, recent 

electricity forward capacity market 

auctions in the PJM market for the 

period of 2014 and 2015 that indicate 

that the capacity markets cleared with 

electricity reserve margins of 20 percent; 

this is in excess of the default reliability 

targets used by the North American 

Electric Reliability Corporation (NERC) 

for the year 2015. One commenter 

quoted NERC, stating that NERC does 

not see impacts from proposed climate 

legislation or anticipated EPA regulation 

as a reliability concern. Another 

commenter noted that the Building and 

Construction Division of the AFL–CIO 

has stated that there is no evidence to 

suggest that the availability of skilled 

manpower will constrain pollution 

control technology installation. In fact, 

according to the commenter, given the 

high levels of unemployment in the 

construction sector, these jobs are much 

needed. 

A number of commenters expressed 

concern that the time frame for 

compliance with a regulation under 

CAA section 112(d) was too short for 

this industry and would result in 

compromising the reliability of 

electricity supply. Commenters asserted 

that reliability would be compromised 

in several ways: (1) EGUs might have to 

temporarily close if the owner or 

operator is unable to install controls on 

the unit within the 3-year time frame or 

3 years plus one; (2) the timing of 

outages to install controls will cause 

short term closures that could threaten 

grid stability; (3) owner/operators may 

shut down EGUs rather than invest in 

retrofits to keep them running and that 

these closures may cause a loss of 

critical generation; and (4) the 

construction of replacement generation 

or implementation of other measures to 

address reliability concerns due to plant 

retirements could take longer than 3 

years, and that units slated for closure 

may be necessary beyond the 3-year 

compliance period but will be unable to 

run because they have not installed the 

necessary controls. 

Response: Clean Air Act section 112 

specifies the dates by which affected 

sources must comply with this rule. 

New or reconstructed units must be in 

compliance immediately upon startup 

or the effective date of this rule, 

whichever is later. Existing sources may 

be provided up to 3 years after the 

effective date to comply with the final 

rule; if an existing source is unable to 

comply within 3 years, a permitting 

authority has the ability to grant such a 

source up to a 1-year extension, on a 

case-by-case basis, if such additional 

time is necessary for the installation of 

controls. 

As is explained earlier in this 

preamble, the 3-year compliance 

window is based on the date that is 60 

days after publication of this rule in the 

Federal Register. Because publication 

doesn’t occur until several weeks after 

the rule is signed by the Administrator, 

the earliest required date for compliance 

would be sometime in March 2015. 

Because the last stage of control 

installations usually needs to occur 

when the unit is off-line and because 

scheduled outages are usually 

scheduled for the spring or fall months 

when peak electric demand is lower, 

this additional time is significant as it 

provides companies an additional 

outage period, the spring of 2015, to 

install controls. 

The EPA has considered the concerns 

raised by commenters and has 

concluded that given the flexibilities 

further detailed in this section, the 

requirements of the final rule for 

existing sources can be met by most 

sources without adversely impacting 

electric reliability. In particular, EPA 

believes that the flexibility of permitting 

authorities to allow a fourth year for 

compliance should be available in a 

broad range of situations (as discussed 

below), and that this flexibility 

addresses many of the concerns that 

have been raised. Furthermore as 

indicated below, in the event that an 

isolated, localized concern were to 

emerge that could not be addressed 

solely through the 1-year extension 

under CAA section 112(i)(3), the CAA 

provides flexibilities to bring sources 

into compliance while maintaining 

reliability. 

The EPA considered the impact that 

potential retirements in response to this 

rule will have on resource adequacy in 

order to gauge the rule’s impact on 

reliability. In considering these impacts, 

the EPA considered both the analysis it 

has conducted as well as analyses 

conducted by a number of other groups. 

The EPA’s analysis shows that the 

expected retirements of coal-fueled 

units as a result of this final rule (4.7 

GW) are fewer than was estimated at 

proposal and much fewer than some 

have predicted.321 The net capacity 

reductions projected by the EPA make 

up less than one-half of one percent of 

the total generating capacity in the U.S. 

and about one and one-half percent of 

U.S. coal capacity. Because concerns 

have been raised that the use of DSI may 

not be as prevalent as the Agency has 

predicted and because this could lead to 

more coal retirements, the Agency also 

performed a sensitivity analysis in 

which fewer DSI systems and more 

scrubber systems were installed. In that 

sensitivity, we see approximately 1 

more GW of retirements. This small 

change would have only a very small 

potential impact on resource adequacy. 

When considering the impact that one 

specific action has on power plant 

retirements, it is important to 

understand that the economics that 

drive retirements are based on multiple 

factors including: expected demand for 

electricity, 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 


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9408 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

322U.S. Department of Energy, December 2011, 

‘‘Resource Adequacy Implications of Forthcoming 

EPA Air Quality Regulations.’’ 

323Bipartisan Policy Center, June 2011, 

‘‘Environmental Regulation and Electric System 

Reliability.’’ 

324PJM 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.’’ 

325See Technical Support Document on Resource 

Adequacy in this Docket. 

number of projected retirements than 

will the impact of this final rule. 

The EPA’s assessment looked at the 

capacity reserve margins in each of 32 

subregions in the continental U.S. 

Demand forecasts used were based on 

EIA projected demand growth. The 

analysis shows that with the addition of 

very little new capacity, average reserve 

margins are significantly higher than 

required. The NERC assumes a default 

reserve margin of 15 percent while the 

average capacity margin seen after 

implementation of the policy is nearly 

25 percent. Although such an analysis 

does not address the potential for more 

localized reliability concerns associated 

with transmission constraints or the 

provision of location-specific ancillary 

services (such as voltage support and 

black start service), the number of 

retirements projected suggests that the 

magnitude of any local reliability 

concerns should be manageable with 

existing tools and processes. 

Several outside analyses have reached 

conclusions consistent with EPA’s 

analysis. The DOE, in December 2011, 

published a report that looked at 

resource adequacy in the bulk power 

system when faced with a stress test 

which was a regulatory scenario far 

more stringent than EPA’s 

regulations.322 For this stress test, in 

addition to CSAPR and MATS 

requirements, each uncontrolled electric 

generator is required to install both a 

wet FGD system and a fabric filter to 

reduce air toxics emissions. If such 

installations are not economically 

justified, this scenario assumes that the 

plant must retire by 2015. In reality, as 

discussed previously, power plant 

owners will have multiple other 

technology options to comply with the 

regulations—options that typically cost 

less than installations of FGDs and 

fabric filters. The analysis finds that 

target reserve margins can be met in all 

regions, even under these stringent 

assumptions. Moreover, in every region 

but one (TRE), no additional new 

capacity is needed. In TRE, the analysis 

finds that less than 1 GW of new natural 

gas capacity would be needed by 2015 

beyond the additions already projected 

to occur in the Reference Case. This 

analysis also finds that the total amount 

of new capacity that would be added by 

2015 is less than the amount that is 

already under development. 

In June 2011, the Bipartisan Policy 

Center issued a report analyzing 

potential collective impacts of EPA’s 

pending power sector rules and 

concluding that ‘‘scenarios in which 

electric system reliability is broadly 

affected are unlikely to occur.’’ 323

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.324 Although PJM’s analysis 

assumes substantially more retirements 

than EPA projects, it nevertheless 

concludes that resource adequacy is not 

threatened in the PJM region. This is 

particularly significant, given that the 

PJM region is one of the largest and 

most heavily dependent on coal-fueled 

generation in the country. The PJM 

analysis notes, as EPA has 

acknowledged, that even where there is 

adequate generation capacity on a 

regional basis, localized reliability 

issues may emerge in connection with 

retirements that may need to be 

addressed. 

The EPA has reviewed industry and 

NERC studies suggesting, contrary to the 

EPA’s and these other groups’ analyses, 

that EPA rules affecting the power 

sector (including this final rule, the 

CSAPR, EPA’s proposed rule addressing 

power plant cooling water intake 

systems under section 316(b) of the 

Clean Water Act (CWA), and EPA’s 

proposed rule addressing coal 

combustion residuals under the 

Resource Conservation and Recovery 

Act) will result in substantial power 

plant retirements. Some of these studies 

predict that such levels of retirements 

will have adverse effects on electric 

reliability in some regions of the 

country. Although the specifics of these 

analyses differ, in general they share a 

number of serious flaws in common that 

call their conclusions into question. 

First, most of these studies make 

assumptions about the requirements of 

the EPA rules that are inconsistent with, 

and dramatically more expensive than, 

the EPA’s actual proposals or final rules. 

For example, a large proportion of the 

retirements projected by several of these 

studies is attributable to their inaccurate 

assumption that EPA’s cooling water 

intake rule under CWA section 316(b) 

would require all or virtually all 

existing power plants to install cooling 

towers. In one study, the reliability 

effects reported are based on inaccurate 

assumptions that all existing EGUs with 

a capacity utilization factor of less than 

35 percent would close, and that all inscope 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; even analyses subsequent to 

the CWA section 316(b) proposal 

continue to inaccurately portray EPA’s 

proposed approach. 

Second, in reporting the number of 

retirements, many analyses fail to 

differentiate between plant retirements 

attributable to the EPA rules and 

retirements of older, smaller, and less 

efficient plants that are already 

scheduled for retirement because 

owners have made business decisions, 

based in significant part on market 

conditions, not to continue operating 

them. 

Third, most of these analyses fail to 

account for the broad range of responses 

available to address electric reliability 

concerns associated with power plant 

retirements, including upgrades to the 

transmission system, construction of 

new generation, and implementation of 

demand-side measures. These measures 

are discussed at greater length below. 

As a preliminary matter, none of these 

situations, either alone or in 

combination, will necessarily lead to an 

electric reliability problem. There is 

excess generating capacity in the 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.325 This analysis 

shows that significantly less capacity 

will close in response to the final rule 

than might have under the proposal. 

Moreover, the regional modeling of 

retirements demonstrates that plants 

that close in response to this rule are 

spread out across the country rather 

than clustered in one area. 

Outside analyses have identified 

many of the same flaws in studies 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9409 

326 James E. McCarthy and Claudia Copeland, 

Congressional Research Service, August 8, 2011, 

‘‘EPA’s Regulation of Coal-Fired Power: Is a ‘Train 

Wreck’ Coming?’’. 

327Bipartisan Policy Center, June 2011, 

‘‘Environmental Regulation and Electric System 

Reliability.’’ 

328As stated above, EPA has provided the 

maximum compliance time authorized under CAA 

section 112(i)(3)(A). 

329Paul 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%20Sotkiewicz-%20Panel%202_0.pdf, slide 6. 

330Form EIA–860 Annual Electric Generator 

Report, http://www.eia.gov/cneaf/electricity/page/ 

eia860.html. 

331BPC slides cited above—slide 5. 

332http://www.exeloncorp.com/Newsroom/pages/ 

pr_20091202_Generation.aspx?k=eddystone. 

333Cromby Units 1 and 2 and Eddystone Units 1 

and 2—Deactivation Study, Updated September 7, 

2010—http://policyintegrity.org/documents/ 

20100907-cromby-and-eddystone-retirement-studyposting-update.pdf. 

projecting large-scale retirements as a 

result of EPA’s power sector rules. For 

example, on August 8, 2011, the 

Congressional Research Service 

(CRS) 326 issued a report concluded that 

studies that assert that EPA rules will 

cause reliability problems, often make 

assumptions about the requirements of 

the rules that are inconsistent with, and 

dramatically more expensive than, the 

EPA’s actual proposals. The CRS further 

noted that EPA’s rules will primarily 

affect units that are more than 40-years 

old, that have not yet installed state-ofthe-art pollution controls, and that are 

inefficient. Many of these plants are 

being replaced by combined cycle 

natural gas plants, driven more my 

lower gas prices than by EPA’s 

regulations. The June 2011 Bipartisan 

Policy Center report referenced above 

likewise highlighted many of these same 

shortcomings in the studies in 

question.327

Although we do not expect to see any 

regional reliability problems, we 

acknowledge that there could be 

localized reliability issues in some 

areas—due to transmission constraints 

or location-specific ancillary services 

provided by retiring generation—if 

utilities and other entities with 

responsibility for maintaining electric 

reliability do not take actions to mitigate 

such issues in a timely fashion. There 

are many potential actions that could be 

taken to address this problem and 

multiple safeguards to assure a reliable 

electricity supply. 

First, utilities can help to assure 

reliability through proactive steps in 

coordination with relevant planning and 

regulatory authorities. As we said in the 

proposal, early planning is key. The 

industry has adequate resources to 

install the necessary controls and 

develop the new capacity that may be 

required within the compliance time 

provided for in the final rule.328

Although there are a significant number 

of controls that need to be installed 

across the industry, with proper 

planning, we believe that the 

compliance schedule established by the 

CAA can be met. Many companies have 

begun to do the detailed analysis and 

engineering and are ahead of others in 

their compliance strategy. There are 

already tools in place (such as 

integrated resource planning, and in 

some cases, forward auctions for future 

generating capacity) that ensure that 

companies adequately plan for, and 

markets are responsive to, future 

requirements such as this final rule. 

Second, companies that intend to 

retire EGUs should formally notify their 

RTO (or comparable planning authority 

in the case of non-RTO regions), state 

regulatory agencies, and regional 

reliability entities as soon as possible of 

their compliance plans, particularly 

with regard to any planned unit 

retirements. As we said before, in most 

places a closing plant will not be a 

cause for concern for reliability. The 

same is true of any outages required for 

retrofitting of units with controls. To the 

extent there is concern, however, early 

notification will provide an opportunity 

for transmission planners, market 

participants, and state authorities to 

develop solutions to avoid a reliability 

problem. In RTOs with forward capacity 

markets, owner/operators that do not 

bid generating capacity that they plan to 

shut down will provide an advance 

signal to market participants to take 

action to assure adequate future 

capacity. In all regions, early and public 

notification will allow market 

participants, planning coordinators and 

state authorities, as appropriate and in 

a timely fashion, to bring new 

generation on line, put demand side 

resources in place, and/or complete any 

transmission upgrades needed to 

circumvent a potential issue. Most RTOs 

only require 45 to 120 days notification 

of closure. In combined comments to 

EPA, 5 RTOs suggested that such 

notification should be made no later 

than 12 months after this regulation is 

final in order to allow a smooth 

transitioning to action to avoid a 

reliability problem. The EPA strongly 

encourages sources to provide notice to 

the RTOs as early as possible and 

believes that responsible owner/ 

operators should and will do the early 

planning for compliance and provide 

early notification of their compliance 

plans, especially where such plans 

include retiring one or more units. 

On the supply side, there are a range 

of options including the development of 

more centralized power resources 

(either base-load or peaking) and/or the 

development of cogeneration or 

distributed generation. Even with the 

current large reserve margins, there are 

companies ready to implement supplyside projects quickly. For instance, in 

the PJM region, there are over 11,600 

MW of capacity that have completed 

feasibility and impact studies; the units 

representing this capacity could be online by the third quarter of 2014.329 The 

EPA notes, as well, that in the 3 years 

from 2001 to 2003, industry brought 

over 160 GW of generation on line.330

Demand side options include energy 

efficiency as well as demand response 

programs. These types of resources can 

also be developed very quickly. In 2006, 

PJM had less than 2,000 MWs of 

capacity in demand side resources. 

Within 4 years this capacity nearly 

quadrupled to almost 8,000 MW of 

capacity.331 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,332 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.333

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-bycase 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 


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9410 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

extension provision because EPA has 

established regulations to implement 

the provision and the provision applies 

to all NESHAP. See 40 CFR 

63.6(i)(4)(A). 

We believe that the permitting 

authorities have the discretion to use 

this extension authority to address a 

range of situations in which installation 

schedules may take more than 3 years 

including: staggering installations for 

reliability reasons or other site-specific 

challenges that may arise related to 

source-specific construction, permitting, 

or labor, procurement or resource 

challenges. Staggered installation allows 

companies to schedule outages at 

multiple units so that reliable power can 

be provided during these outage 

periods. It can also be helpful for 

particularly complex retrofits (e.g., 

when controls for one unit need to be 

located in an open area needed to 

construct controls on another unit). The 

additional 1-year extension would 

provide an additional two shoulder 

periods (i.e., seasons flanking annual 

high-demand periods) to schedule 

outages, thus enabling owners/operators 

to gain the full benefit of staggering 

outages in support of complex 

installations. The EPA believes that 

although most units will be able to fully 

comply within 3 years, the fourth year 

that permitting authorities are allowed 

to grant for installation of controls is an 

important flexibility that will address 

situations where an extra year is 

necessary. That fourth year should be 

broadly available to enable a facility 

owner to install controls within 4 years 

if the 3-year time frame is inadequate for 

completing the installation. 

As we indicated at proposal, this 

source category is unique due to the 

large, complex and interconnected 

nature of electrical generation, 

transmission and distribution, and the 

critical role of the electric grid in the 

functioning of all aspects of the 

economy. The grid functions as an 

interconnected system that supplies 

electricity to end users on a continuous 

basis. Safe, reliable operation of the grid 

requires coordination among actions 

taken at individual units, including 

timing of outages for the installation of 

controls, derating, or deactivation. It 

was for this reason that we specifically 

addressed in the proposed rule 

reasonable interpretations of the phrase 

‘‘installation of controls’’ in CAA 

section 112(i)(3)(B). We determined that 

it was important to provide Title V 

permit authorities with information that 

might be useful if they were asked to 

authorize a fourth year for specific 

EGUs. 

The EPA took comment on whether 

the construction of on-site replacement 

power could be considered the 

‘‘installation of controls’’ such that a 

fourth year would be available while the 

replacement unit is being completed for 

a unit that is retiring (e.g., a case when 

a coal-fueled unit is being shut down 

and the capacity is being replaced onsite 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 as the ‘‘installation of 

controls’’ such that it would be 

appropriate for permitting authorities to 

grant a 1-year extension beyond the 3- 

year compliance time-frame. In 

particular, commenters suggested that 

the 1-year extension should be available 

for a unit if a company’s compliance 

choice was to retire that unit but doing 

so within the 3-year time-frame caused 

reliability problems for any of the 

following reasons: (1) Generation from 

the retiring unit is needed to maintain 

reliability while other units install 

emission controls; (2) new off-site 

generation was being built to replace the 

retiring unit, but the new generation 

was not scheduled to be operational 

within the 3-year time-frame and any 

gap between the time the existing unit 

retires and the new unit comes on line 

would cause reliability problems; and 

(3) transmission upgrades were needed 

in order to maintain electric reliability 

after the unit retired but could not be 

completed within 3 years. 

While the ultimate discretion to 

provide a 1-year extension lies with the 

permitting authority, EPA believes that 

all three of these cases may provide 

reasonable justification for granting the 

1-year extension if the permitting 

authority determines, for example, 

based on information from the RTO or 

other planning authority or other 

entities with relevant expertise, that 

continued operation of a particular unit 

slated for retirement for some or all of 

the additional year is necessary to avoid 

a serious risk to electric reliability. 

In a case where pollution controls are 

being installed, or onsite replacement 

power is being constructed to allow for 

retirement of older, under-controlled 

generation, a determination that an extra 

year is necessary for compliance should 

be relatively straightforward. In order to 

install controls, companies will have to 

go through a number of steps fairly early 

in the process including obtaining 

necessary building and environmental 

permits and hiring contractors to 

perform the construction of the 

emission controls or replacement 

power. This should provide sufficient 

information for a permitting authority to 

determine that emission controls are 

being installed or that replacement 

power is being constructed. Because 

companies will need to develop this 

information early in the process and 

because a determination can easily be 

made as to whether the schedule will 

exceed 3 years, the EPA believes that 

Title V permitting authorities should be 

able to quickly make determinations as 

to when extensions are appropriate. 

In the three cases related to retirement 

of a unit without construction of onsite 

replacement power, additional 

information is needed. The Title V 

permitting authority should request that 

the affected company or companies 

provide information, including, for 

example, from the RTO or other 

planning authority for the relevant 

region, the state electric regulatory 

agency, NERC or its regional entities, 

and/or FERC or the DOE, demonstrating 

that retirement of a particular unit 

within the 3-year compliance period 

would result in a serious risk to electric 

reliability. 

The first two situations involving a 

retiring unit—where one or more related 

existing units are upgrading pollution 

controls or a new unit is being 

constructed off-site—are similar to the 

situation we discussed in the proposed 

rule wherein a retiring unit at a facility 

runs an additional year while a 

replacement unit on the same site is 

constructed. In each of these situations, 

the retiring unit would be allowed to 

run so a unit compliant with the rule 

(either a retrofitted existing unit or a 

new unit) can come on line. We believe 

that these situations may, in the 

appropriate circumstances, constitute 

ones in which a 1-year extension for the 

retiring unit is ‘‘necessary for the 

installation of controls.’’ In these two 

situations, however, we believe that it 

would be appropriate for the Title V 

permitting authority to consider 

reliability concerns as a necessary factor 

before granting the additional year 

because continuing operation of the 

retiring unit is only ‘‘necessary’’ to the 

extent it is required for reliability. In 

each of these situations, the permitting 

authority should determine that the 

retiring unit is necessary to maintain 


srobinson on DSK4SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9411 

334SO3 Control: AEP Pioneers and Refines Trona 

Injection Process for SO3 Mitigation, Coal Power, 

March 2007, http://www.coalpowermag.com/

plant_design/SO3-Control-AEP-Pioneers-andRefines-Trona-Injection-Process-for-SO3- 

Mitigation_29.html. 

335NRG Energy letter to RGGI, Inc, November 22, 

2010, http://www.rggi.org/docs/NRG_Nov_2010.pdf. 

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 is similar: 

Reductions of the existing unit’s HAP 

emissions (through retirement) while 

maintaining electric reliability. If such 

situations develop and the reliability 

problem has been properly 

demonstrated, permitting authorities 

should consider whether an extension 

under CAA section 112(i)(3)(B) may be 

provided. 

The EPA continues to believe, based 

on the analysis discussed at the 

beginning of this section, that most, if 

not all, units will be able to comply 

with the requirements of this rule 

within 3 years. The EPA also believes 

that making it clear that permitting 

authorities have the authority to grant a 

1-year compliance extension where 

necessary, in the range of situations 

described above, addresses many of the 

other concerns that commenters have 

raised. The EPA believes that the 

number of cases in which a unit is 

reliability critical and in which it is not 

possible to either install controls on the 

unit or mitigate the reliability issue 

through construction of new generation, 

transmission upgrades, or demand-side 

measures, within 4 years, is likely to be 

very small or nonexistent. This view is 

consistent with statements from 

commenters explicitly mandated with 

ensuring grid reliability. 

The EPA’s authority to provide relief 

from the requirements of this final rule 

beyond the fourth year is limited by the 

statute. If reliability issues do develop, 

however, the CAA provides 

mechanisms for sources to come into 

compliance while maintaining electric 

reliability. One area where the EPA has 

some measure of flexibility is with 

respect to the exercise of its 

enforcement authorities. The Agency 

has used such authority in the past to 

bring sources into compliance with the 

requirements of the CAA while 

maintaining electric reliability, although 

these authorities are not as flexible as 

suggested by some commenters. 

The EPA generally does not speak 

publicly to the intended scope of its 

enforcement efforts, particularly well in 

advance of the date when a violation 

may occur. In light of the importance of 

ensuring electric reliability, however, 

the Office of Enforcement and 

Compliance Assurance will separately 

publish a document that articulates our 

intended approach with respect to 

sources that operate in noncompliance 

with this final rule to address a specific 

and documented reliability concerns. 

That document provides a pathway 

for reliability critical units (as such 

units are described in the document) to 

achieve compliance within an 

additional year. The result is that 

qualifying reliability critical units may 

come into compliance within up to 5 

years. This pathway is structured to 

maintain reliability, to ensure CAA 

compliance and to increase certainty for 

sources in planning by allowing a unit 

owner/operator to determine whether it 

qualifies for a compliance schedule well 

in advance of the MATS compliance 

deadline. 

The EPA believes that there will be 

few, if any, situations in which it will 

be necessary to have recourse to the 

processes discussed in the document 

just described, and that there are likely 

to be fewer, if any, cases in which it is 

not possible to mitigate a reliability 

issue within the further year 

contemplated under that document. 

However, there is always the possibility 

that some unit owner/operator will be 

unable to address its reliability issues 

within 5 years and there is always the 

possibility that a unit owner/operator 

will be unable to timely comply with 

the MATS for some other reason. 

Consistent with its longstanding 

historical practice under the CAA, the 

EPA will address individual noncompliance circumstances on a case-bycase basis, at the appropriate time, to 

determine the appropriate response and 

resolution. 

A number of commenters also raised 

concerns about inconsistencies between 

the compliance timelines under this 

final rule and existing state agreements 

with specific owners/operators to install 

pollution control equipment and/or 

retire EGUs. The EPA believes the 

flexibilities provided in this discussion 

allow for some discretion to address 

those cases, but that they may not be 

fully addressed. The EPA is supportive 

of such efforts and believes they can 

have important multi-pollutant health 

and environmental benefits. To the 

extent that the flexibilities discussed 

here do not fully address a particular 

situation, we encourage states and 

sources to contact the EPA as early as 

possible to discuss their individual 

circumstances. 

G. Cost and Technology Basis Issues 

1. Dry Sorbent Injection 

Comment: Several commenters stated 

that there is limited commercial 

operating experience in using DSI to 

control acid gas emissions from coalfired boilers. They suggest that the 

technology is not adequately proven for 

use in this application. 

Other commenters disagree with 

statements made that DSI is not proven. 

One commenter stated that DSI is a 

mature technology. The commenter 

indicated that DSI is well suited for 

units that burn fuels with lower or midlevel sulfur contents, and is among the 

viable options available for a number of 

sources to achieve the proposed HCl 

limits. Thus, the commenter believes 

that DSI represents a real technology 

control option for many units, and is 

among the suite of technology options 

that certain units will be able to employ 

to meet the proposed HCl limit. 

Response: As explained in this 

response and elsewhere in this 

preamble, the EPA agrees that DSI 

technology is proven and ready for 

commercial use in controlling acid gases 

from coal combustion. One of the largest 

coal-burning electric utilities in the U.S, 

American Electric Power (AEP), 

pioneered the practical use of DSI with 

trona, a sodium-based sorbent, for SO3

mitigation. American Electric Power has 

implemented trona injection for that 

purpose across its entire bituminous 

coal-fired fleet where both SCR and wet 

FGD systems are in place.334 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.335 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 


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9412 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

336 Dominion Energy, BART Analysis for the 

Kincaid Power Plant, January 2009, http://

www.epa.state.il.us/air/drafts/regional-haze/bartkincaid.pdf. 

337 Dry Sorbent Injection Systems for Acid Gas 

Control, Babcock & Wilcox, 2010, http:// 

www.babcock.com/library/pdf/ps-451.pdf. 

338Technologies for Acid Gas Control, Babcck & 

Wilcox, 2011, http://www.babcock.com/library/pdf/ 

ps-457.pdf. 

339Solvay Chemicals, Inc., HCl Removal in the 

Presence of SO2 Using Dry Sodium Sorbent 

Injection, http://www.solvair.us/SiteCollection

Documents/presentations/20111214_hcl_

presentation.pdf. 340United Conveyor Corporation, Dry Sorbent 

Injection for Simultaneous SO2, HCl, and Hg 

Removal, October 2011, http://unitedconveyor.com/ 

uploadedFiles/Systems/Systems_Sub/

McIlvaine%20Multipollutant%20Removal

%20Oct%202011.pdf. 

625 MW units at the Kincaid plant in 

Illinois.336 One of the largest suppliers 

of air emission control systems in the 

world, vouches that DSI is commercially 

proven for acid gas control:337 338

Comment: Numerous comments were 

received on EPA’s IPM modeling of DSI 

in the MATS analysis. A few 

commenters stated that DSI will not 

work on bituminous coals. Some 

commenters stated that DSI is only 

suitable for use on low sulfur, low 

chlorine western coals. Others stated 

that DSI is only likely to be used on 

relatively small units, and that larger 

units would use scrubbers for acid gas 

control. Several commenters expressed 

the opinion that because there is little 

commercial operating experience in 

using DSI to control SO2 emissions from 

coal-fired boilers, EPA’s IPM modeling 

assumptions on the efficacy and cost of 

the DSI control option are unjustifiably 

optimistic. Some commenters believe 

that DSI will not be as economic or as 

widely applicable for either SO2 or HCl 

control as projected by EPA’s IPM 

modeling. Commenters observe that wet 

or dry scrubbers for FGD, longerstanding 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 leachate 

containing sodium and other 

compounds that are challenging to 

handle, thus requiring special landfill 

designs and a high cost for landfill 

disposal of DSI waste. 

Response: The EPA believes that its 

representation of DSI in MATS 

compliance modeling is reasonable, is 

properly limited to applications that are 

technically feasible, and reflects a 

conservative approach to modeling 

future use of this technology. 

The EPA disagrees that its IPM 

modeling of DSI is overly optimistic and 

therefore underestimates the costs of 

MATS compliance. In its IPM modeling, 

EPA restricts the availability of the DSI 

option to only those units that use or 

switch to relatively low sulfur coal: Less 

than 2 lb SO2/MMBtu (see IPM 

documentation in the docket). The 

EPA’s IPM projections for MATS 

compliance, therefore, already include 

the costs of any additional FGD 

scrubbers that are economically justified 

and projected for use on units using 

higher sulfur coals. The EPA models 

DSI assuming fine-milled trona as the 

injected sorbent. As mentioned by 

several commenters, sodium 

bicarbonate (SBC), which is processed 

from trona, is also suitable for use with 

DSI. Sodium bicarbonate is more 

reactive with acid gases than trona. It 

would require less tonnage of sorbent 

and less tonnage of waste disposal than 

trona for the same SO2 removal effect, 

albeit at somewhat higher sorbent cost. 

Non-sodium based sorbents such as 

hydrated lime (calcium based) could 

also be used. Therefore, EPA’s modeling 

of DSI technology does not include the 

full spectrum of sorbent choices that 

real-world applications enjoy, meaning 

that there may be opportunities for 

lower-cost applications of DSI that are 

not captured in EPA’s projections for 

MATS. The EPA models DSI with trona 

injection rates corresponding to 70 

percent SO2 removal for all coals, 

assuming that an equivalent amount of 

sorbent is needed to provide 90 percent 

HCl removal, regardless of the low 

sulfur and chlorine content of western 

coals. 

Senior technical staff from the EPA 

have carefully evaluated the key 

assumptions regarding the cost and 

operation of emission control 

technologies. In general, these staff 

believe that trona should have strong 

HCl reaction selectivity and, 

consequently, EPA’s assumed trona 

injection rates may be overstated. The 

extent to which this assumption may 

actually overstate DSI control costs can 

be observed through DSI pilot testing for 

Solvay Chemicals by the Energy & 

Environmental Research Center (EERC) 

at the University of North Dakota.339

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 finemilled trona, when well mixed into 325 

°F flue gas upstream of a FF, provides 

90 percent HCl removal at a SO2

removal rate of less than 20 percent (as 

compared to EPA’s modeling 

assumption of aligning 90 percent HCl 

removal with sorbent injection designed 

to achieve 70 percent SO2 removal). The 

data show that 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 

Conveyor 340 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 

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 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9413 

341TW Lugar, et al., The Ultimate ESP Rebuild: 

Casing Conversion To a Pulse Jet Fabric Filter, a 

Case Study, Electric Power Conference, May 2009, 

http://www.cecoenviro.com/uploads/

ESP%20to%20Fabric%20Filter%20Baghouse%20

Conversion%20-%20Buell%20Case%20History.pdf. 

342http://www.wma-minelife.com/trona/

tronmine/tronmine.htm. 

343http://www.wma-minelife.com/trona/

TronaPage2/trona_production.htm. 

comments and a more thorough review 

of the ICR data, the EPA has introduced 

in final MATS modeling a recognition 

that the relatively high alkalinity of ash 

from subbituminous and lignite coals 

‘‘removes’’ much of the HCl that would 

otherwise be emitted from combustion 

of these particular coals. The 2010 ICR 

data indicate that in some cases the ash 

itself removes sufficient HCl from these 

coals for MATS compliance; in effect, 

these acid-gas emissions are absorbed by 

coal ash and are captured by particulate 

control devices instead of being emitted 

in gaseous form. As a conservative 

measure, EPA’s revised final MATS 

modeling assumes that 75 percent of 

HCl is removed by the ash for these 

coals. In the event that ash capture in 

practice is more effective than this 75 

percent assumption, then EPA’s analysis 

projects a conservatively higher level of 

DSI installations (and, thus, compliance 

cost) than would actually occur in 

practice. In any case, it appears that 

significantly less sorbent injection 

would actually be required in practice 

than assumed by EPA for these low 

sulfur, low chlorine coals, and that the 

IPM projected DSI 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 airto-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,341 an option not modeled in IPM, 

but that would likely have a lower 

capital cost than a retrofitted FF. In the 

MATS proposal EPA modeled DSI with 

a waste disposal cost of $50/ton, based 

on a Sargent & Lundy DSI cost model 

prepared for EPA (see proposal IPM 

documentation in the docket). The EPA 

has continued to model DSI at this 

waste disposal cost for analysis of the 

final rule. However, recent discussions 

between senior technical staff from the 

DOE and the EPA have suggested that in 

some situations sodium sulfates, that 

would be formed by the injection of 

trona, could potentially leach out of the 

fly ash/sorbent mixture on contact with 

water. Although the technical staff 

recognized that these concerns are more 

relevant to bituminous coal-fired units 

where ashes are not cementitious, 

unless mixed with limestone or lime, 

they suggested that the impacts of 

potentially higher disposal costs be 

evaluated. Based on public comments, 

further investigations by Sargent & 

Lundy, and suggestions from the EPA 

and DOE technical staff, EPA’s analysis 

of the final rule has included an IPM 

sensitivity case using a DSI waste 

disposal cost of $100/ton. The 

sensitivity case indicates that a 100 

percent increase in assumed DSI waste 

disposal cost produces slightly less than 

a 1 percent increase in the projected 

cost of the rule. 

Comment: A few commenters 

expressed the concern that there is an 

inadequate supply of trona to support 

DSI operations at the levels projected by 

the EPA for MATS compliance. 

Response: The EPA projects that just 

over 50 GW of coal-fired 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 2010.342 343 If the EPA’s 

assumed trona injection rates are as 

much as 50 percent greater than actually 

needed for at least 90 percent HCl 

control, as discussed above, and given 

that some subbituminous coals will 

apparently need little or no sorbent 

injection for HCl control, there may 

already be an adequate surplus of trona 

production capacity to support DSI for 

MATS compliance. The EPA, therefore, 

concludes that trona supply for DSI is 

either already adequate, or will require 

at most a small increase in production 

capacity. 

For all of these reasons, the EPA 

believes that its representation of DSI in 

MATS compliance modeling is 

reasonable, is properly limited to 

applications that are technically 

feasible, and reflects a conservative 

approach to modeling future use of this 

technology. 

2. Economic Hardship 

a. Job Losses and Economic Impacts 

Comment: Several commenters 

indicated that they believe the proposed 

rule will weaken industry, cause job 

losses and hurt power consumers. One 

commenter reported that the proposed 

rule will affect 1,350 coal and oil-fired 

units at 525 power plants and that 

NERC reports that by 2018 nearly 50,000 

MW of capacity will be retired by the 

proposed rule. Many of these 

commenters compared the cost 

estimated by EPA to a variety of other 

sources that estimate substantially 

higher costs of the rule. The 

commenters expressed concern that 

electricity price increases are likely to 

be up to 24 percent in some regions as 

a result of the proposed rule. In addition 

to the economic difficulty the proposed 

rule could place on consumers, the 

commenter believes that many in the 

energy sector will lose their jobs due to 

coal-fired capacity losses. The 

commenters believe the effects on coalfired plants in the Southeast especially 

will mean the loss of high-paying, highskilled jobs and drastic price increases 

in energy costs. Additionally, 

commenters expressed concern that 

increased electricity and natural gas 

prices would impact businesses in 

multiple sectors across the country. 

Response: The EPA disagrees with the 

estimates presented by the commenters. 

The EPA has updated its analysis to 

reflect the final MATS. The Agency 

estimates the annual costs of the final 

rule in 2015 to be $9.6 billion in 2007 

dollars. The estimate of early 

retirements of coal-fired units due to 

this rule is 4.7 GW, lower than the level 

estimated at proposal. Both of these 

estimates were prepared using the IPM, 

a model that has been extensively 

reviewed and has been utilized in 

several rulemakings affecting the power 

generation sector over the last 15 years. 

The Agency’s analyses are credible and 

accurate to the extent possible, and all 

assumptions and data are made public. 

Limitations and caveats to these 

analyses can be found in the RIA for this 

rule. 

The EPA estimates that there will be 

an increase of 3.1 percent in retail 


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9414 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

344EIA Annual Energy Outlook 2010 annual total 

electricity prices from 1960 to 2010, Table 8–10. 

345 Ibid, EIA AEO 2010, Table 8–10. 

346 Ibid, EIA AEO 2010, Table 8–10 for price 

levels; and Chapter 3 of the RIA for electricity price 

differential. 

347A ‘‘job-year’’ is a combined measure of jobs 

and job duration which is equivalent to one person 

being employed for one year. For example, 2 jobyears could represent two years of employment for 

one worker, one year of employment for two 

workers, or 6 months of employment for four 

workers. Estimates of employment changes that 

involve non-permanent workers are usually 

reported in job years to give a sense of the total 

employment effects. 

348 It should be noted that if more labor must be 

used to produce a given amount of output, then this 

implies a decrease in labor productivity. A decrease 

in labor productivity will cause a short-run 

aggregate supply curve to shift to the left, and 

businesses will produce less, all other things being 

equal. 

349BEA. (2007b). Commodity-by-Industry Direct 

Requirements after Redefinitions, 2002. Available 

in: 2002 Summary Tables, 2002 Benchmark InputOutput Data. Retrieved from http://www.bea.gov/ 

industry/io_benchmark.htm#2002data. 

electricity price on average in the 

contiguous U.S. in 2015 as an outcome 

of this rule, with the range of increases 

from 1.3 percent to 6.3 percent in 

regions throughout the U.S. No region of 

the U.S. is expected to experience a 

double-digit increase in retail electricity 

prices in 2015 or in any year later than 

that, according to the Agency’s analysis, 

as a result of this rule. To put this in 

context, the roughly 3 percent 

incremental increase in aggregate enduser electricity prices projected to occur 

over the next 4 years is about the same 

as the 3 percent absolute average change 

in total end-user electricity prices 

observed on an annual basis.344

Furthermore, the roughly 3 percent 

incremental price effect of this rule is 

small relative to the changes observed in 

the absolute levels of electricity prices 

over the last 50 years, which have 

ranged from as much as 23 percent 

lower (in 1969) to as much as 23 percent 

higher (in 1982) than prices observed in 

2010.345 Even with this rule in effect, 

electricity prices are projected to be 

lower in 2015 and 2020 than they were 

in 2010.346

The Agency found that the readily 

discernible impact on long-term 

employment nationally within the most 

directly affected sectors should be small 

and the EPA also estimated that about 

46,000 job-years 347 of one-time 

construction labor could be supported 

or created by this rule. This includes 

jobs manufacturing steel, cement and 

other materials needed to build 

pollution control equipment, jobs 

creating and assembling pollution 

control equipment, and jobs installing 

the equipment at power plants. 

Potential job increases from increased 

output by lower-emitting facilities (such 

as increased generation from wellcontrolled coal-fired plants that replace 

generation from older coal-fired plants) 

are expected to partially or fully offset 

potential job losses resulting from 

reduced output from higher-emitting 

facilities. The EPA analysis projects a 

net change in the directly affected EGU 

sector of between 15,000 net jobs lost to 

30,000 net jobs gained on an annual 

basis.348 See Chapter 6 of the RIA for 

further details. 

The EPA has also looked at the 

possibility that changes in the price of 

electricity may influence the levels and 

geographic distribution of downstream 

economic activities, and associated 

employment. Projecting how potentially 

higher electricity prices may affect 

various downstream economic activities 

in particular regions as a result of this 

rule is challenging for several reasons: 

(1) There are significant uncertainties 

regarding projections of consumer- and 

location-specific electricity price 

changes in response to future firmspecific compliance strategies; (2) the 

availability of competitively-priced 

alternative energy sources (including 

energy conservation) and less 

electricity-intensive substitute goods 

and services may significantly mitigate 

potentially adverse economic 

consequences resulting from projected 

increases in electricity prices in ways 

which are not captured effectively in 

currently available models; and (3) 

available modeling tools are not 

configured to capture the effects over 

time of economically significant effects 

of cleaner air (e.g., reductions in 

medical expenditures and 

improvements in labor productivity 

resulting from fewer lost work days) 

achieved by rules evaluated using single 

target year criteria pollutant and/or HAP 

benefits projections. After considering 

these methodological limitations, the 

Agency concludes that there is not a 

satisfactory methodology for projecting 

the downstream economic (including 

employment) effects of any changes in 

electricity prices due to this rule. 

We expect the downstream economic 

effects of this rule to be small because 

electricity is only a small factor in the 

production of most goods and 

services.349 A 3 percent increase in enduser electricity prices translates to a 

much smaller effect on prices and 

potential output of goods and services 

from end-users of electricity. Over time, 

the incremental effect of this rule on 

electricity prices is projected to 

diminish significantly; for example the 

difference in expected prices is 

projected to narrow from 3.1 percent in 

2015 to 2.0 percent in 2020 as shown in 

Chapter 3 of the RIA. 

Despite the absence of a satisfactory 

methodology for quantifying the 

potential economy-wide effects 

(including employment) of any potential 

increases in electricity prices resulting 

from this rule, the EPA expects the 

incremental effects of this rule on 

electricity prices to be small given the 

projected electricity price increases 

relative to historical levels and volatility 

in end-user electricity prices. Based on 

these projections and contextual 

information, the Agency believes that 

the incremental effects on electricity 

prices and economic activity of this rule 

are likely to be small relative to other 

factors influencing electricity prices, 

overall employment, and other aspects 

of economic activity. 

Comment: Several commenters 

considered the proposed rule to be a tax 

on the American public, since utilities 

implementing upgrades will pass the 

costs on to the consumer. Commenters 

questioned the preference of Americans 

to subsidize renewable energy sources 

and put money into the proposed rule 

instead of other environmental 

programs with greater benefits. 

Commenters explained that the tax-like 

price increase reduces income of energy 

consumers and depresses business 

development. The commenters used 

California as an example of a state that 

uses low rates of coal-based electricity 

and cites companies that have left the 

state as a result of substituting higher 

cost forms of electricity for coal. A 

commenter stated that coal-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 and leads 

to job losses and lost tax revenues, given 

the restrictive timeframe for 

compliance. 

Response: The Agency does not agree 

that this rule creates or alters any taxes 

on affected sources required under this 

rule to reduce their emissions of toxic 

air pollutants, nor are taxes created or 

altered or imposed on consumers of 

electricity which is provided to the 

market by affected sources. Moreover, 

unlike a tax, this rule does not generate 

government revenue. The rule does, 

however, indirectly address the problem 

of the ‘‘externality cost’’ of higher health 

risks and other adverse effects on the 

populations exposed to toxic air 

pollution emissions from affected 

sources. This rule may have the effect of 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9415 

350http://www.epa.gov/airmarkets/images/

CoalControls.pdf. 

reducing or eliminating a market 

distortion that provides an implicit 

subsidy to affected facilities. This 

implicit subsidy results from the fact 

that some facilities currently can avoid 

the costs of toxic air pollution controls 

by imposing higher health and other 

costs on those who are exposed to 

higher levels of toxic air pollution. The 

Agency also disagrees with the 

implication that the costs incurred by 

less-controlled sources to bring their 

toxic air emissions in line with their 

better-controlled competitors will lead 

to significant or debilitating changes in 

market and economic conditions. The 

Agency’s estimate of the potential 

increase in retail electricity price is an 

average of 3.1 percent in 2015, with a 

range of increases by region from 1.3 

percent to 6.3 percent. As shown in 

Chapter 3 of the RIA, the higher rates of 

potential electricity price increase tend 

to occur in those regions where 

electricity prices have been relatively 

low, due to some extent to reliance on 

coal-fired units which have been 

cheaper to operate due to 

underinvestment in toxic air pollution 

controls.350 As shown in Chapter 3 of 

the RIA, all regions with year 2015 

projected percentage increases in retail 

electricity prices above the contiguous 

U.S. average are also projected to have 

baseline retail electricity prices which 

are below the contiguous U.S. average 

price level in that year. In addition, 

natural gas prices will only increase by 

0.3 to 0.6 percent on average over the 

time horizon of 2015 to 2030. As 

discussed above, for consumers of 

electricity in the commercial and 

industrial sectors, electricity tends to be 

a fairly small fraction of total costs of 

production, implying that the average 

projected electricity price increase of 3 

percent will lead to only a small 

fractional change in the costs of 

providing goods and services to the 

economy. While some residential 

electricity consumers may similarly see 

a small price increase in retail 

electricity prices, it should be noted that 

these consumers tend to reside in the 

same area or region as the affected 

facility and so will also experience the 

improvement in air quality from the 

reductions due to the rule. The 

reduction in health risk and other 

improvements to quality of life 

associated with lower exposure to toxic 

and other air pollutants achieved by this 

rule will confer benefits on these 

consumers which include lower risks of 

premature mortality, lower morbidity, 

and improved productivity and 

competitiveness of U.S. workers due to 

reduction in work days lost to air 

pollution-related illness. The benefits of 

these improvements are projected to 

exceed costs of compliance by affected 

sources by at least six-fold. The 

potential price increases in electricity 

and natural gas should be considered in 

light of the substantial health, welfare, 

and economic benefits achieved by this 

rule. 

Comment: Many commenters 

expressed support for the EPA’s impact 

analysis and disputed claims by other 

commenters that the projected rule will 

harm economic growth. A number of 

commenters mentioned testimonials by 

power company CEOs stating that the 

proposed rule will not affect the 

economic health of the industry and a 

survey showing nearly 60 percent of the 

coal-fired units already comply with the 

EPA’s proposed Hg standard, and 

several other meaningful quotes from 

utility executives. The commenters also 

pointed out that 17 states already 

require plants to address Hg pollution, 

with some imposing more stringent 

emission limits than the EPA proposes. 

The commenters believe that utilities 

use the threat of power plant closures 

and lost jobs to delay Hg reductions 

from coal-fired plants. Commenters also 

believe that the rules will drive 

innovation and job creation as new 

technologies to reduce pollution are 

created. Several commenters quoted the 

Economic Policy Institute finding that 

the proposed rule will increase job 

growth by 28,000 to 158,000 jobs by 

2015 (including approximately 56,000 

direct jobs and 35,000 indirect jobs), the 

University of Massachusetts study that 

showed an increase 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 4,200 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 the rule, 

EPA has conducted a technically sound 

and conservative benefit-cost analysis 

showing that the proposed rule’s 

estimated benefits are at least five times 

as high as its costs. One commenter 

stated, ‘‘With sound, albeit unduly 

conservative, econometric modeling, 

EPA has also determined that the Toxics 

Rule will promote economic growth and 

create jobs in both the long and short 

term.’’ Two commenters cited the EPA 

impact analyses by Dr. Charles Cicchetti 

which confirm this finding and state 

that the analysis underestimates the 

rule’s net benefits and positive impacts 

on the nation’s economy. By 

considering some benefits not 

monetized in the EPA analysis, Dr. 

Cicchetti concludes that the proposed 

rule will create $52.5 to $139.5 billion 

in net benefits annually, create 115,200 

jobs, generate annual health savings of 

$4.513 billion, annual increases in GDP 

of $7.17 billion and $2.689 billion in 

additional annual tax revenues, and 

spur innovation and modernization of 

EGUs. The commenters state that the 

study findings show no need to delay 

implementation of the rule or needlessly 

duplicate economic analyses already 

completed. 

Commenters reported that multiple 

researchers confirmed that the EPA’s 

estimates of economic stimulus are 

conservative and that the proposed rule 

will stimulate job growth. A commenter 

quotes Dr. Josh Bivens of the Economic 

Policy Institute, who also found that 

EPA’s conclusions were conservative. 

Dr. Bivens concluded, ‘‘The EPA RIA on 

the proposed toxics rule makes a 

compelling case that the rule passes any 

reasonable cost-benefit analysis with 

flying colors—the monetized benefits of 

longer lives, better health, and greater 

productivity dwarf the projected costs of 

compliance * * * Whether regulation 

in general and the toxics rule in 

particular costs jobs is an empirical 

question this paper attempts to answer. 

In particular, this paper examines the 

possible channels through which the 

proposed toxics rule could affect 

employment in the United States and 

finds that claims that this regulation 

destroys jobs are flat wrong: ‘‘The jobsimpact of the rule will be modest, but 

it will be positive.’’ His report details 

the following major findings: 

1. The proposed rule would have a 

modest positive net impact on overall 

employment, likely leading to the 

creation of 28,000 to 158,000 jobs 

between now and 2015. 

2. The employment effect of the 

[MATS] on the utility industry itself 

could range from 17,000 jobs lost to 

35,000 jobs gained. 

3. The proposed rule would create 

between 81,000 and 101,000 jobs in the 

pollution abatement and control 

industry (which includes suppliers such 

as steelmakers). 

4. Between 31,000 and 46,000 jobs 

would be lost due to higher energy 

prices leading to reductions in output. 

5. Assuming a re-spending multiplier 

of 0.5, and since the net impact of the 

above impacts is positive, another 9,000 

to 53,000 jobs would be created through 

re-spending. 


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9416 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

351EIA Annual Energy Outlook 2010 annual total 

electricity prices from 1960 to 2010, Table 8–10. 

352See ‘‘An Assessment of the Feasibility of 

Retrofits for the Mercury and Air Toxics Standards 

Rule’’ in the docket. 

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 also sees large price 

increases for customers if units are 

converted to natural gas, which is 

approximately 2.5 times more expensive 

than the coal that the commenter 

currently uses to generate electricity. 

Response: The EPA’s estimates of 

increase, relative to the baseline, in the 

retail electricity price range from 1.3 

percent to 6.3 percent regionally in 

2015, with an average increase 

nationwide of 3.1 percent in 2015. Lowincome households will thus see some 

increase in electricity price, but this 

increase should be modest. In addition, 

the increase in the price of natural gas 

as a result of this rule is expected to be 

0.3 to 0.6 percent over a time horizon 

of 2015 to 2030. This increase in price 

is low enough that electricity customers 

should not experience a major increase 

in price resulting from any modest 

changes to electricity generated by 

natural gas. The roughly 3 percent 

incremental price effect of this rule is 

small relative to the changes observed in 

the absolute levels of electricity prices 

over the last 50 years, which have 

ranged from as much as 23 percent 

lower (in 1969) to as much as 23 percent 

higher (in 1982) than prices observed in 

2010.351

c. State or Regional Impacts 

Comment: Multiple commenters 

expressed concern over the impact of 

the rule on electricity prices and 

reliability in specific states or regions. 

These commenters were concerned that 

these impacts would adversely affect 

specific industries such as construction 

and manufacturing. One commenter 

suggested the EPA consider regional 

differences that will impact system 

reliability and costs, such as the 

increased impacts on regions relying 

heavily on coal and oil and encourages 

cooperation between the EPA and state 

and federal energy and environmental 

regulators. 

Response: The Agency has studied 

possible impacts on resource adequacy 

as a result of this rule, and has 

determined that these impacts should 

not be significant. Furthermore, 

industry, along with relevant federal 

agencies, has the tools needed to 

address any reliability concerns. The 

Agency has prepared an updated 

feasibility TSD in support of the final 

rule, which is in the docket for this 

rulemaking.352 The Agency has 

considered impacts on a regional basis 

as part of its overall analyses done using 

the IPM; these results are documented 

in the RIA for the rule and in the 

feasibility TSD. 

The EPA’s analysis shows that retail 

electricity price increases will not fall 

disproportionately on a specific region. 

In fact, those regions experiencing the 

largest change in prices are projected to 

have retail electricity prices below the 

national average both in the absence of 

MATS and after the implementation of 

MATS. In Chapter 3 of the RIA, the EPA 

presents retail electricity prices by 

region in 2015, for both the base case 

and MATS policy case. The six regions 

that are projected to have retail 

electricity prices above the national 

average price in 2015 in the absence of 

MATS are projected to have increases 

that are below the national average 

increase following the implementation 

of MATS. Those regions that have 

projected retail electricity price 

increases that are above the national 

average are all projected to have retail 

electricity prices below the national 

average in the absence of MATS. 

Comment: A commenter quoted 

National Mining Association statistics 

showing coal is responsible for $65.738 

billion in annual economic activity, 

produces 1,798,800 jobs and $36.345 

billion in annual labor income. The 

commenter reports that regions such as 

Appalachia, the Midwest and Rocky 

Mountain West will be significantly 

affected by the proposed rule, including 

increased unemployment. Other 

commenters stated that communities 

near existing coal-fired generation units 

will be especially hard-hit if the plants 

are permanently retired. The 

communities will suffer from job loss 

and diminished tax revenue. 

Response: The Agency’s analysis, as 

found in the RIA, shows that impacts to 

these regions are mixed. For 

Appalachia, coal production is 

projected to fall by 6 percent in 2015, 

while the Western coal producing 

region will experience a decrease of 3 

percent in production in 2015. The 

Interior region is projected to see a 9 

percent increase in production. Retail 

electricity prices are expected to 

increase by 1.3 percent to 6.3 percent in 

various parts of the country in 2015. 

Also, the estimated number of early 

retirements according to the Agency that 

may result from this rule is 4.7 GW in 

2015, or less than 2 percent of all U.S. 

coal-fired capacity in that year. Thus, 

there may be some negative impacts 

from this rule in some regions, but these 

same regions will also experience some 

of the benefits, such as reduced 

premature mortality from less exposure 

to PM2.5 emissions as shown in Chapter 

5 of the RIA. As discussed previously, 

the EPA’s analysis shows that retail 

electricity price increases will not fall 

disproportionately on a specific region. 

In fact, those regions experiencing the 

largest change in prices are projected to 

have retail electricity prices below the 

national average both in the absence of 

MATS and after the implementation of 

MATS. 

The results of the EPA’s employment 

analysis, found in Chapter 6 of the RIA, 

indicate that the final MATS has the 

potential to provide significant shortterm employment opportunities, 

primarily driven by the high demand for 

new pollution control equipment. While 

the employment gains related to the 

new pollution controls are likely to be 

tempered by some losses due to certain 

coal retirements, some of these workers 

who lose their jobs due to plant 

retirements could find replacement 

employment operating the new 

pollution controls at nearby units. 

Finally, job losses due to reduced coal 

demand are expected to be offset by job 

gains due to increased natural gas 

demand, resulting in a small positive 

net change in employment due to fuel 

demand changes. 

While shifts in employment are 

difficult for those directly affected, and 

the Agency remains concerned about 

the challenges job shifts can bring to the 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9417 

353U.S. Bureau of Labor Statistics, 2011. 

Extended Mass Layoffs in 2010. http://www.bls.gov/ 

mls/mlsreport1038.pdf. 

individuals affected, Bureau of Labor 

Statistics data indicate that compliance 

with pollution control requirements is a 

relatively very small contributor to 

overall employment shifts in the U.S. 

economy. Specifically, the main cause 

of mass layoffs over the last four years 

according to 2007 to 2011 Bureau of 

Labor Statistics data is ‘‘lack of business 

demand,’’ accounting for over 40 

percent of the layoffs reported by 

industry. In contrast, all types of 

regulatory actions (including health, 

safety, and environmental) by all levels 

of government (Federal, State, local) 

combined were cited as the primary 

factor in only 0.2 percent of mass layoffs 

over the same period.353

d. Retirements of Coal-Fired EGUs and 

Shutdowns 

Comment: A commenter discussed 

the economic factors behind EGU 

retirements. These factors include the 

cost of alternative generation using 

natural gas, the cost of implementing 

demand response measures that can be 

bid into capacity markets, and the cost 

of continuing to generate power from an 

existing unit. The commenter states that 

regardless of the costs associated with 

the Toxics Rule and other EPA electric 

power industry regulations, some power 

plants were already economically 

unsustainable. The commenter quotes 

M.J. Bradley, who points out, ‘‘[o]f the 

122 coal units in PJM with capacity less 

than or equal to 200 MW, 35 failed to 

recover their avoidable costs and 

another 52 were close to not recovering 

those costs. Therefore, in PJM * * * in 

addition to approximately 10 GW of 

coal generation that has or will be 

retired during the 7 years from 2004 to 

2011, another 11 GW faces a troubling 

economic outlook.’’ The commenter 

provides confirmation of this by the 

most recent PJM capacity auction, 

where approximately 6.9 fewer GW of 

coal-fired capacity cleared the auction 

(1.85 fewer GW were offered) as 

compared with the prior year’s auction, 

and an additional 4.836 GW of new 

demand response (energy efficiency) 

resources cleared the auction. Thus, the 

commenter states, some claims linking 

retirements to the MATS are overstated 

and misleading. The commenter gives 

the example of the American Electric 

Power attempt to link its planned plant 

closures to the MATS, but those plants 

already are slated to either close or to 

upgrade controls to comply with 

existing laws. The commenter goes on to 

quote three independent studies that 

support the finding that over 50 percent 

of the fleet is equipped with scrubbers 

and the number will increase to nearly 

2⁄3 by 2015. 

Response: The EPA agrees with the 

findings of the independent studies 

mentioned by the commenter. 

e. Impacts on Mining 

Comment: Multiple commenters 

mention the proposed rule’s impact on 

mining. One commenter mentioned 

increasing energy costs for the U.S. 

mining industry, resulting in fewer 

projects and associated jobs, as well as 

increasing dependence on foreign 

mineral resources. Commenters see 

mining impacts being disproportionally 

large for lignite mines, which are 

dependent on their co-located lignitefired 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 which EPA includes the 

impacts on the mining industry that will 

result from this rule. 

Response: The Agency presents 

impacts on the coal mining sector from 

this rule in the RIA. Given the modest 

increase in coal and other energy costs 

associated with the rule, the Agency 

does not expect widespread impacts on 

coal mining. The Agency’s modeling 

accounts for all emission controls and 

programs installed and/or implemented 

up through December 2010, including 

those in Texas. 

f. Flexible Regulations 

Comment: Several commenters 

expressed concern over the potential 

impacts of the regulation and believe 

that the requirements should be more 

flexible in order to mitigate these 

impacts. 

Response: The EPA believes the 

requirements of the final rule have been 

made as flexible as possible consistent 

with the CAA. The final rule allows 

some flexibility, including allowing 

averaging across units in the same 

subcategory at a facility, allowing for an 

option of an input or output standard 

for existing units, and allowing for 

alternative compliance options (e.g., for 

coal, filterable PM or total non-mercury 

metallic HAP or individual HAP 

metals). In addition, the Agency is not 

prescribing specific technologies as part 

of this final rule, but instead requiring 

emissions limitations be met. This 

approach allows the industry to find the 

most cost-effective approach to meeting 

the requirements while ensuring 

considerable public health benefits. 

g. Temporary vs. Permanent Jobs 

Comment: A commenter expressed 

disagreement with the EPA prediction 

of new jobs created, because the 

commenter believes far more plants will 

shut down than the EPA predicts, 

resulting in higher job losses. The 

commenter also pointed out that while 

jobs running power plants are 

permanent, the jobs predicted to be 

created by the proposed rule are short 

term construction jobs, and will all 

occur in the same short timeframe for 

compliance. The commenter also stated 

that the EPA estimate does not include 

the opportunity cost of lost construction 

jobs due to new power plants that will 

not be constructed due to the 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 longterm employment impacts to the electric 

power sector in the RIA for the rule, and 

that estimate shows a range of impacts 

from 15,000 net jobs lost to 30,000 net 

jobs gained (all annual), but also 

recognizes important limitations to 

these estimates. The Agency’s estimate 

of impacts to short-term jobs, including 

those in construction, accounts for both 

losses and gains that result from the 

rule. This is shown in Chapter 6 of the 

RIA. 

Comment: Commenters believe that 

installation of new pollution controls 

would be a job-growth opportunity in 

their states because money spent on 

controls for power plants creates highquality jobs in steel, cement and other 

materials, as well as in the assembling 

of the equipment as well as installing 

and operating it. A commenter shares 

the Alabama Fisheries Association 

estimate that the water-based recreation 

industry brings in over $1 billion per 

year to the state’s economy though the 

state ranks third for imperiled fish with 

61 bodies of water cited for Hg 

contamination. The commenter believes 

the HAP accumulating in the waterways 


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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 

over time will help to improve 

waterways in Alabama and thus help 

the water-based recreation in that state. 

More information on the benefits of Hg 

and other HAP reductions can be found 

in Chapter 4 of the RIA for the rule. The 

Agency also agrees with the commenter 

that the addition of control equipment 

for EGUs may stimulate employment in 

a variety of industries. 

h. Natural Gas 

Comment: A commenter states that 

natural gas use is only an option in 

places where infrastructure exists to 

supply sufficient natural gas to the EGU 

and other local needs and reports that 

year-round reliable gas delivery is rare 

due to requirements to meet the other 

needs. The commenter says that gas 

interruptions are prevalent in the 

winter, but can happen year-round, and 

the costs of establishing a natural gas 

line to a power plant can be tens of 

millions of dollars or more, and moving 

a plant to a gas source can take many 

years. The commenter describes the 

options for a Norwalk Harbor plant, and 

explains that the modifications are 

costly and difficult even before 

considering the modifications needed to 

alter the boiler and fuel supply system 

to allow natural gas combustion. 

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 cost-effective approach to 

addressing harmful emissions that are 

covered by this action. The Agency 

believes that cost-effective technologies 

exist today and have been deployed on 

many power plants, and utilities will be 

able to find intelligent solutions to 

address harmful emissions. The EPA 

has provided supporting information as 

part of the preamble and RIA for this 

rule, along with the feasibility TSD, 

which demonstrate the availability and 

performance of technologies to meet the 

requirements of the final rule. 

Comment: A commenter discusses the 

factors that could lead to higher natural 

gas prices not currently reflected in the 

EPA impact projections, including 

industrial load and demand not 

rebounding to 2008 levels and the 

influence of liquefied natural gas 

exports. The commenter asks that the 

EPA address a variety of factors related 

to its natural gas assumptions. 

Response: The Agency has fully 

documented its assumptions and 

framework for modeling natural gas in 

IPM for both the proposed and final 

MATS. This information can be found 

in Chapter 10 of the IPM documentation 

(http://www.epa.gov/airmarkets/ 

progsregs/epa-ipm/docs/v410/ 

Chapter10.pdf). The documentation 

provides a thorough overview of the 

natural gas module, describes the very 

detailed process-engineering model and 

data sources used to characterize North 

American conventional, 

unconventional, and frontier natural gas 

resources and reserves and to derive all 

the cost components incurred in 

bringing natural gas from the ground to 

the pipeline. Also documented are the 

resource constraints, liquefied natural 

gas (LNG), demand side issues, the 

natural gas pipeline network and 

capacity, procedures used to capture 

pipeline transportation costs, natural 

gas storage, oil and natural gas liquids 

(NGL) assumptions, and key gas market 

parameters. 

i. Compliance Timeline and General 

Timeline 

Comment: A commenter states that 

the proposed rule will require costs be 

passed on to consumers, meaning state 

public utility commissions will be 

flooded with requests for rate increases 

from utilities trying to recover 

expenditures. The short deadline will 

also result in a large number of 

extension requests made to state 

permitting authorities, further 

burdening them. 

Response: The compliance date for 

this rule for existing sources will be 3 

years and 60 days after publication of 

the final rule in the Federal Register, or 

approximately March 2015. Thus, there 

will be some time before the impacts of 

this rule such as any increase in retail 

electricity prices become a concern. It 

also should be noted that increases in 

retail electricity prices will be 3.1 

percent on average in 2015, with a range 

regionally from 1.3 percent to 6.3 

percent. 

Comment: A commenter reports that 

they will need to install add-on 

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 preconstruction steps that would be 

required, as well as the new 

construction activities and the 

challenges of scheduling sequence 

relative to interconnections and other 

tie-in considerations involved in 

compliance. 

Response: The Agency has addressed 

concerns with the feasibility and timing 

of control installations in its report on 

the subject (see feasibility TSD 

contained in the docket for this rule). 

Comment: Multiple commenters do 

not believe that labor availability will 

constrain control installation in the 

required timeframe and cites an 

Institute of Clean Air Companies (ICAC) 

response that it will not for these 

reasons: 

1. The power sector has demonstrated 

ability to install large number of systems 

in short time period; 

2. The majority of coal plans have 

installed control systems already; 

3. Fewer resource and labor-intensive 

control options being used for 

compliance; and 

4. End users have utilized cost 

reducing and implementation efficiency 

strategies for efficient deployment of 

technologies. 

Another commenter states that a wide 

range of technical and economically 

feasible practices and technologies are 

available currently to meet the emission 

limits and are in use around the 

country. 

Response: These comments are 

generally consistent with the 

conclusions of the Agency’s analyses on 

feasibility of control installations for 

this rule as found in the feasibility TSD 

in the docket for this rulemaking. 

j. Burden Outweighs Environmental 

Gain 

Comment: Several commenters state 

that the EPA has no data relating to 

benefits from reducing non-mercury 

HAP, so the costs of the proposed rule 

exceed the HAP benefits by 29,000 

times. One commenter states that the 

impact analysis was largely focused on 

Hg with little support for other HAP 

reductions and failed to provide account 

of true costs and benefits. 

Response: While we are not able to 

monetize the benefits from reductions of 

non-mercury HAP that will take place, 

these important effects are discussed 

qualitatively in Chapter 4 of the RIA. 

The quantified benefits of this rule 

include the reductions in non-HAP 

emissions such as SO2 and PM2.5 that 

will occur as a co-benefit of this rule as 

modeled by EPA. The total benefits are 

estimated to outweigh the total annual 

costs of the rule by a margin of either 

3 to 1 or 9 to 1, depending on the 

benefits estimate and discount rate 

used. These reductions are credible and 

are considerable in size. The estimates 

of these benefits reflect the latest 

scientific understanding on the subject. 

More information on the estimates and 


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the methodology for their preparation 

can be found in the RIA for the rule. 

Comment: Several commenters 

consider the proposed rule to be the 

most expensive clean air rule ever. They 

point out the estimated $10.9 billion 

annual cost in 2015 and approximate 

1,200 existing coal-fired EGUs affected, 

both of which were estimated by the 

EPA. Commenters believe the EPA’s 

estimates are incorrect and the true cost 

will be far more, due to cumulative 

effects of all proposed power sector 

rules, and indirect costs from job losses, 

reduced productivity and 

competitiveness resulting from 

electricity costs. They ask the EPA to 

keep these high costs in mind when 

evaluating impacts of the proposed rule 

and consider the costs with respect to 

the benefits. One commenter requests 

that the EPA explain how its approach 

utilized ‘‘the best available techniques 

to quantify anticipated present and 

future benefits and costs as accurately as 

possible’’ and includes analyses by EIA, 

EEI, NERC, NERA, Credit Suisse, ICF, 

and Burns & McDonnell. 

Response: As noted earlier, the 

Agency did not prepare a cumulative 

impact analysis to accompany the rule 

for the following reasons: (1) The 

various EO requirements that the 

Agency must comply with require us to 

estimate impacts specific to this rule; (2) 

decisionmakers and the public need to 

know the impacts specific to a 

particular rule in order to judge the 

merits of the regulation; and (3) 

estimates specific to a particular rule are 

more transparent than those from a 

cumulative impact analysis. A 

cumulative impact analysis lumps 

several regulations together and can 

potentially mask a high-cost/low benefit 

regulation among other rules that may 

have large net benefits. By analyzing 

each regulation separately, EPA makes 

clear statements about the impacts, 

costs, and benefits that are estimated as 

a result of this particular regulation. 

This does not, however, mean EPA 

has failed to incorporate these 

regulations into this analysis. The 

inclusion of CSAPR and other 

regulatory actions (including federal, 

state, and local actions) in the IPM base 

case reflects the level of controls that are 

likely to be in place in response to other 

requirements apart from MATS. This 

base case provides meaningful 

projections of how the power sector will 

respond to the cumulative regulatory 

requirements for air emissions, while 

isolating the incremental impacts of 

MATS. These results are presented in 

Chapter 3 of the RIA. 

Additionally, the Agency does reflect 

on the cumulative impacts of our 

regulations. In March 2011, EPA issued 

the Second Clean Air Act Prospective 

Report which assessed the benefits and 

costs of regulations pursuant to the 1990 

Clean Air Act Amendments. The study 

examines the cumulative impact of 

these regulations (found at http:// 

www.epa.gov/air/sect812/feb11/ 

summaryreport.pdf). As shown in the 

report, the direct benefits from the 1990 

Clean Air Act Amendments are 

estimated to reach almost $2 trillion for 

the year 2020, a figure that dwarfs the 

direct costs of implementation ($65 

billion). The full report is at http:// 

www.epa.gov/air/sect812/ 

prospective2.html. 

The direct benefits of the 1990 Clean 

Air Act Amendments and associated 

programs are estimated to significantly 

exceed their direct costs, which means 

economic welfare and quality of life for 

Americans were improved by passage of 

the 1990 Amendments. The wide 

margin by which benefits are estimated 

to exceed costs, combined with 

extensive uncertainty analysis, suggest 

it is very unlikely this result would be 

reversed using any reasonable 

alternative assumptions or methods. 

The analysis presented in the RIA for 

the current regulation uses a similar 

methodology. 

The techniques employed by the 

Agency for generating benefits and 

costs, and consider the most recent and 

complete data available to the Agency. 

The EPA recognizes that the analyses 

have caveats and limitations, and we 

discuss our analyses and their caveats 

and limitations in the RIA for the rule, 

as well as in the benefits section of the 

preamble. The Agency has also revised 

the cost analyses for the final rule to 

reflect data received in public 

comments on the proposed rule, and 

costs are lower than when the rule was 

proposed. 

k. Impact on State Regulators 

Comment: Several commenters 

expressed concern over the burden 

imposed on state regulatory agencies by 

the rule. 

Response: The Agency has estimated 

the costs of implementation of the rule 

to states that own EGUs affected by the 

rule, and has included this analysis in 

the RIA. The Agency has updated this 

analysis for the final rule and it is 

included in the RIA. While the EPA has 

not prepared an analysis of the impacts 

of the rule on state programs, the 

Agency does not believe the rule will be 

unduly burdensome to the state 

regulatory agencies. The 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 health-based ambient 

air requirements. This is a far more costeffective approach than controls at 

smaller facilities and is the lowest cost 

path to improved public health and a 

cleaner environment. 

Response: The EPA acknowledges 

that the HAP standards in this final rule 

will lead to considerable co-benefit 

reductions in PM and SO2. 

l. Miscellaneous 

Comment: A few commenters 

discussed the impact of the rule on the 

federal budget deficit. One commenter 

points out that the proposed rule will 

affect the federal budget in two ways: 

1. Direct compliance costs to electric 

generating units (EGUs) owned by 

federal agencies; and 

2. Pass-through compliance costs paid 

in the form of higher prices for 

electricity purchased by federal 

agencies. 

Response: The Agency estimates the 

direct compliance costs to EGUs that are 

federally owned as part of the overall 

cost analysis completed for the proposal 

and disclosed in the RIA for the rule. 

The Agency does not provide an 

estimate of the impact on federal 

agencies from higher electricity prices 

associated with the rule, however. This 

type of analysis is not required under 

EO 12866 and statutory requirements. 

H. Testing and Monitoring 

Comment: Commenters raised 

numerous issues with the testing and 

monitoring requirements for initial and 

continuous compliance. The following 

discussion highlights the comments and 

responses to a number of the critical 

issues and describe where the 

comments have resulted in a significant 

rule change or where we disagreed with 

commenters’ suggestions of issues or 

need for changes in the rule. Additional 

comments and responses are addressed 

in the Response to Comments document 

included in the docket for the final rule. 

Test Methods. A number of 

commenters suggested that we should 

allow for the use of Method 5B to 

determine compliance with the PM 

emission limit. In addition, a number of 


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354http://www.icci.org/reports/10Laudal6A-1.pdf. 

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 scrubber-controlled 

utility boilers under 40 CFR part 60, 

subparts D, Da and Db, we are excluding 

Method 5B for demonstrating 

compliance with the filterable PM 

emissions standard in this final rule. 

The extended high temperature heating 

of the filters prior to weighing as 

specified in Method 5B would introduce 

differences between the compliance test 

data and the data that underlie the 

filterable particulate standard. Because 

the test data that underlie and filterable 

particulate standard are based primarily 

on Method 29 and Method 5 data 

collected at 320 °F or comparable 

filterable particulate methods, we are 

specifying those same methods for 

determining compliance with the 

standard. 

For stack test frequency, we modified 

the final rule to require quarterly testing 

to demonstrate continuous compliance. 

In addition, we agree that testing should 

be required only for the emission limits 

that your source is complying with, and, 

thus, the final rule does not require 

testing of both the pollutant and the 

surrogate. 

Comment: Fuel Analysis Methods. A 

number of commenters raised various 

concerns with the fuel analysis methods 

specified in the proposed rule. 

Response: Based on the comments 

received and a further review of the 

technical challenges associated with the 

proposed fuel analysis requirements, we 

have not finalized the proposed fuel 

analysis requirements. As the rule no 

longer requires operating limits based 

on fuel content or fuel analysis, the 

comments on this issue are largely 

moot. For LEEs, we agree that the 

proposed LEE ongoing eligibility 

requirements were overly burdensome 

and restrictive. As a result, existing 

solid or liquid fired units that qualify 

for Hg LEE status will be required to 

conduct a 30-day test for Hg using 

Method 30B each year. Neither fuel 

analysis nor adherence to an operating 

limit will be required. Should an annual 

test show ineligibility for LEE status, the 

source will revert to the requirements 

for Hg monitoring using CEMS or 

sorbent traps or, for oil-fired units, 

quarterly emissions testing. Existing 

solid or liquid fired units that qualify 

for non-mercury LEE status will be 

required to conduct a stack test every 3 

years, and neither fuel analysis nor 

adherence to an operating limit will be 

required. Should the stack test show 

ineligibility for LEE status, the source 

will revert to using CEMS or PM CPMS 

or conducting quarterly emissions 

testing. 

Comment: Operating Parameter 

Limits: Some commenters objected to 

the use of enforceable operating 

parameter limits, requested that the rule 

be more consistent with the compliance 

assurance monitoring program, and 

raised specific objections to certain 

parameters required for certain control 

devices. Commenters also raised 

concerns about a PM CEMS operating 

limit establishing a de facto more 

stringent PM emission limit than the 

one being tested for under the total PM 

standard in the proposal. 

Response: We believe that continuous 

monitoring in the form of CEMS, 

sorbent trap monitoring systems, and 

PM CPMS, or frequent stack emissions 

testing are appropriate to ensure 

ongoing compliance with this final rule. 

We also agree with commenters that 

some of the monitoring provisions in 

the proposal may have been duplicative 

and unnecessary. In order to provide 

flexibility in the final rule, we have 

retained a source’s ability to define an 

operating limit and to monitor using a 

PM CPMS as an option to periodic 

filterable PM emissions testing. 

The final rule establishes the PM 

CPMS as an operating limit monitor and 

not a direct filterable PM emission 

monitoring requirement that meets PS 

11 requirements. Although we recognize 

the importance of continued control 

device performance to ensure emissions 

minimization, we also are aware that 

other rules that apply to these units 

including, but not limited to, the 

Operating Permits rule, the Compliance 

Assurance Monitoring rule, the ARP 

rules, and the NSPS already require 

continuous monitoring in most cases. 

Those rules will remain in effect so the 

need to impose additional operating 

limits monitoring or CEMS on those 

units is much reduced. 

The final rule also provides for the 

use of a PM CEMS to determine 

compliance with the filterable PM 

emission limit if the source elects to use 

this approach. In that case, the PM 

CEMS is used as the direct method of 

compliance and no additional testing is 

required other than tests that are 

required as part of satisfying the 

requirements in Performance 

Specification 11 in Appendix B to 40 

CFR part 60 and Procedure 2 in 

Appendix F to part 60. The EPA 

provided this option in response to the 

comments in order to provide a 

straightforward direct measure of 

compliance that some sources may want 

to implement. 

Comment: Hg CEMS. Commenters 

raised a number of technical concerns 

about Hg CEMS. Many commenters 

requested modifications so that the 

requirements would be more consistent 

with 40 CFR part 75 monitoring 

requirements. Some commenters 

questioned the ability of the technology 

to demonstrate compliance with 

emission limits at very low levels 

especially for new sources. Commenters 

also opposed high data availability 

requirements given that the technology 

is new and difficult to operate and 

maintain. 

Response: We indicated in the 

proposed rule the intent to adopt 

CAMR-based requirements for Hg 

monitoring in place of the general 40 

CFR part 63 performance specifications 

and QA requirements. With CAMR, 

these operating and reporting 

requirements for Hg CEMS went 

through notice and comment 

rulemaking for the same sources as 

covered by this final rule. Although 

CAMR was set aside on other grounds, 

these technical specifications and QA 

requirements reflect significant input 

from stakeholders and analysis by the 

EPA to establish an appropriate 

foundation for Hg monitoring at electric 

utilities under the CAA. For the final 

rule, we have made conforming changes 

to ensure that this intent is carried out 

effectively throughout the rule text and 

Appendix A, as well as including 

certain additional clarifications based 

on the input received in response to the 

proposed rule. We have also removed a 

cycle time test as unworkable for certain 

types of Hg CEMS. 

The final rule provides the option for 

use of either Hg CEMS or sorbent trap 

monitoring systems. We believe the 

record clearly shows these to be proven 

technologies each providing certain 

advantages. For existing and some of the 

new unit standards, the level of the 

NIST-traceable Hg gas standards will be 

adequate and consistent with existing 

applications of Hg CEMS. For the lowest 

limits and other applications where an 

integrated sampling system offers 

advantages, affected facilities may opt to 

use sorbent trap monitoring systems to 

comply. There are data in the recent 

draft report entitled ‘‘Determining the 

Variability Of CMMS At Low Hg 

Levels,’’354 that demonstrate reasonable 


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performance of at least one Hg CEMS at 

Hg levels below 1.0 microgram per 

cubic meter (mg/m3) down to 

approximately 0.1 mg/m3. Finally, there 

is no specific minimum data availability 

requirement for Hg CEMS (or any other 

CMS required under this final rule). 

This issue is discussed further below. 

Comment: SO2 CEMS: Although 

commenters were generally supportive 

of the ability to use SO2 CEMS for units 

with FGD installed to demonstrate 

compliance with an alternate SO2

emission limit instead of the HCl 

emission limit, there were some 

concerns with aspects of the proposal. 

Commenters requested that the SO2

monitoring requirements rely on 40 CFR 

part 75 given that their sources were 

already meeting those requirements and 

that this rule not establish any new 

requirements, especially a fourth 

linearity level and the application of 7- 

day calibration error tests for units with 

low concentrations (where 40 CFR part 

75 provides an exemption). Commenters 

were also concerned that the rule 

language only allows the option where 

the FGD is operated ‘‘at all times’’ 

which seems to imply that the option is 

not allowed if the source ever bypasses 

the FGD for start-up, shutdown, or 

malfunction reasons. 

Response: After reviewing the 

comments and assessing the need for an 

additional calibration gas at the 

emissions limit, we have removed this 

requirement from the final rule while 

retaining the requirement for a linearity 

check even for SO2 monitors with low 

span values (≤ 30 ppm). A source can 

already report linearity tests for these 

units within the context of the existing 

ECMPS reporting without triggering any 

critical errors. This test can be 

accommodated within the current 

framework without causing issues for 40 

CFR part 75 reporting. The requirement 

for a 7-day calibration error test is 

removed. For the ‘‘at all times’’ 

language, we have clarified this in the 

final rule. The intent is that the FGD be 

operated during all routine boiler 

operations, and not operated 

intermittently, seasonally, or on some 

other non-fulltime basis. 

Comment: HCl CEMS. In general, 

commenters argued that HCl CEMS do 

not have an approved performance 

specification and are not widely 

demonstrated as a proven technology. 

Those concerns were also mentioned for 

HF CEMS. 

Response: We disagree with 

commenters’ contention that continuous 

HCl monitoring is premature or not 

available for the measurement at the 

emission limits set in the final rule. HCl 

CEMS are being used on source 

categories such as municipal waste 

combustors and EGUs. We have 

reviewed HCl CEMS vendor technology 

claims and found sufficient capability to 

support this rule requirement. We are 

engaged with representative 

stakeholders to develop a generic 

performance specification for HCl CEMS 

scheduled for completion in time to be 

responsive to compliance with this rule. 

The final rule provides several 

options for HCl and/or HF monitoring 

including: 

(1) Using Fourier Transform Infrared 

(FTIR)-based HCl CEMS and/or HF 

CEMS complying with Appendix B to 

the rule which relies on PS 15, 

(2) Seeking approval for an alternative 

HCl monitoring procedure through 40 

CFR 63.7(f), 

(3) Monitoring compliance 

continuously with the alternate SO2

emission limit at coal-fired or other 

solid fuel affected facilities equipped 

with FGD technology for SO2, and 

(4) Quarterly reference method 

testing. 

Including these options in the final 

rule provides flexibility to adopt CEMS 

monitoring options as the technology 

continues to mature and the new, nontechnology-specific EPA performance 

specifications becomes available. 

Comment: Bypass Stacks. Several 

commenters raised concerns about the 

technical feasibility of monitoring 

bypass stacks with a CEMS. 

Response: We have modified the 

bypass stack monitoring requirements. 

Under 40 CFR part 75, we allow the use 

of a maximum potential concentration 

value for reporting when emissions are 

vented to a bypass stack. That approach 

works within the context of an 

emissions trading program, but is not 

appropriate when evaluating 

compliance with a specific emission 

limit. Thus, we have provided two other 

options. One is to monitor the bypass 

stack, consistent with the final rule. The 

other is to treat any hours of bypass 

stack emissions as periods of monitor 

downtime and hours of deviation from 

the monitoring requirements. Note that 

a source’s units must continue to meet 

their 30-boiler operating day emissions 

limits during malfunction periods. 

Comment: 40 CFR part 75 Issues. 

There were a number of general 

comments about the value of relying on 

40 CFR part 75 requirements, including 

elements such as conditional data 

validation. The commenters generally 

agreed that the 40 CFR part 75 bias test 

and bias adjustment factor, and the 40 

CFR part 75 substitute data provisions 

should not apply. Instead of substitute 

data, many commenters suggested that 

we needed to clarify the valid reasons 

for monitor downtime and establish an 

appropriate minimum data availability 

requirement. 

Response: We have attempted to 

harmonize the CEMS requirements in 

this final rule with those under 40 CFR 

part 75 wherever appropriate. One of 

those examples is the inclusion of 

conditional data validation for Hg 

CEMS. We disagree that this final rule 

needs a minimum data availability 

requirement. We have not included any 

specific minimum data availability 

requirement for CEMS or other 

monitoring in this final rule nor do we 

provide a specific tool for data 

substitution. We believe that there are 

other provisions in the final rule to 

provide incentives to conduct 

monitoring in a manner consistent with 

good air pollution control practices and 

to provide data sufficient to demonstrate 

compliance with a relatively long-term 

(30-boiler operating day) emissions rate 

limit. We agree that data quality 

certainty associated with any calculated 

value decreases with the collection of 

less data such as would occur with 

extended periods of monitoring system 

downtime. Even so, we believe also that 

it is necessary and critical for 

compliance with the regulation that a 

source use all measured data collected 

during an averaging period to assess 

compliance regardless of any periods of 

missing data. Sources should not 

disqualify any data otherwise meeting 

required data quality requirements 

simply because there were data missing 

for other hours or days of the averaging 

period. 

Instead of a minimum data 

availability threshold that would 

invalidate data collected for some 

averaging periods because one did not 

collect data for at least a specified 

percent of an averaging time, the final 

rule requires that a source report as 

deviations to the rule failure to collect 

data during required periods if these 

deviations are not covered by 

exceptions allowed in the final rule. 

On the issue of applying a data 

substitution procedure to represent 

actual emissions or pollution control 

performance, we are not requiring data 

substitutions under this rule. We 

believe, however, that defensibility 

concerns make it incumbent on the 

source to collect and evaluate other 

information in accordance with 40 CFR 

section 63.6(f)(3) during periods of 

monitoring downtime to assure 

compliance with the applicable 

emissions limitations and standards. 

We believe that enforcement 

authorities also can and should 

determine whether a source is meeting 

any monitoring system operating 


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9422 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

requirements. Should the source or the 

enforcement authority be concerned 

about the representativeness of data 

such as during periods of missing data, 

either one may consider collecting 

information through other means (e.g., 

supplemental emissions testing) to fill 

data gaps not only because such gaps 

are deviations from the rule but such 

gaps can lead to uncertainty about 

compliance status. 

We further believe that the final rule 

provides sufficient means to ensure 

CMS performance and ongoing 

compliance without specifying an 

arbitrary numerical minimum data 

availability or data substitution 

requirement. We believe that specifying 

failure to collect required or otherwise 

excepted data as a deviation from the 

rule will provide the necessary 

incentive to collect data sufficient to 

demonstrate compliance with the limits 

in the final rule. 

Comment: Recordkeeping. Several 

commenters opposed the requirements 

related to maintaining records on site 

and for 5 years. 

Response: We believe the 

recordkeeping and retention 

requirements are consistent with other 

requirements already in place, 

specifically 40 CFR 63.10 (b). 

In addition, the 5-year retention 

period is the general rule for all 

recordkeeping for all sources under the 

part 70 operating permits program. 

Given that the General Provisions for 40 

CFR part 63 and part 70 already 

establish a 5-year retention period, we 

believe it is justified in using those 

precedents for the retention periods 

under this subpart. If we stayed silent 

on retention period in this subpart, the 

General Provisions would provide for 

the 5-year retention as would the part 70 

requirements. Thus, this action does not 

establish any new retention 

requirements, but merely confirms that 

the existing retention requirements 

apply. 

Comment: Electronic Reporting. In the 

proposed rule, we requested comment 

on using ECMPS for reporting under 

this rule, as well as other options 

including the ERT. Commenters 

generally supported the use of ECMPS, 

especially for CEMS data. Some 

commenters requested an additional 

rulemaking on the specific data 

elements to be collected. There were 

some concerns raised about the ERT 

given experience during the 2010 ICR 

process during the development of this 

rule. 

Response: We recognize that 

emissions reporting for continuously 

measured pollutants (SO2, NOX, etc.) 

and for periodically measured 

pollutants (PM, HAP metals, etc.) have 

different data demands. We recognize 

that minor revisions of the ECMPS will 

fulfill our data needs for most 

continuously measured pollutants and 

we will make these modifications for 

receipt of the additional CEMS data. We 

also recognize the need for substantial 

modifications to the ECMPS to 

accommodate the data needs for 

periodically measured pollutants and 

certain CEMS data such as PM CEMS 

data and possibly HAP metals CEMS 

data. Although major modifications of 

the ECMPS would be required for 

periodic compliance tests by isokinetic 

and instrumental test methods (as well 

as certain types of CEMS), only minor 

revisions are required of the ERT to 

receive these tests. We are 

implementing the changes in the ERT 

that are required to provide the software 

tools to implement the delivery of these 

performance test data to us. 

The electronic submission of 

compliance test reports to us through 

the Central Data Exchange (CDX) is not 

solely for the purpose of developing 

improved emissions factors as some 

commenters assert. Although populating 

WebFIRE will allow us to improve 

emissions factors, we intend to use data 

stored in WebFIRE as the primary 

location for compliance test reports for 

use by regulatory authorities. The 

electronic submission of compliance 

test reports is a continuation of our 

efforts to bring the submission and 

sharing of environmental data into the 

modern age. The storage of this 

compliance data in our WebFIRE 

provides a convenient location which is 

already used to store source test data. 

As federal and state and local 

agencies’ data systems mature, 

information provided through the ERT 

will be used to populate these data 

systems. We are currently upgrading the 

AIRS Facility System and expect to 

replace manually entered information 

with electronic population from the 

ERT. We are also working with several 

state and local agencies to adopt the use 

of the ERT for delivery of compliance 

test reports. The ERT is also much 

improved since the version used during 

the 2010 ICR process, and there is no 

expectation that the information to be 

reported under this final rule will be as 

extensive as some of the data reported 

for the 2010 ICR purposes. 

We disagree that a separate and 

independent regulatory action is 

required to implement electronic 

reporting for selected regulated sources. 

Each of these regulatory actions for 

selected source categories provides 

ample notice and the opportunity for 

individuals to provide comment. We 

also disagree that the system to receive 

the compliance data must be operational 

prior to establishing the requirement for 

regulated sources to submit compliance 

data electronically. We are on track to 

have the capability to receive electronic 

compliance tests through our CDX in 

sufficient time to receive all utility 

source test reports required by this final 

rule. 

We do plan a separate and 

independent regulatory action to 

implement electronic reporting for 

regulated entities which are covered by 

past and future rules. Although we have 

provided draft procedures for the 

development of emissions factors, that 

effort is an ancillary effort to the 

electronic delivery of compliance test 

reports. It is our intention to convert to 

the electronic delivery and storage of all 

air emissions compliance source test 

data. With this transition, we believe 

this valuable information will be more 

readily available not only for 

compliance purposes but also for a 

variety of other uses. 

I. Emissions Averaging 

Comment: In response to our request 

for comments on the suitability of 

emissions averaging and need for a 

discount factor, we received a range of 

suggestions, including requests for 

clarification regarding eligibility, points 

for and against the need for a discount 

factor, and suggestions to ease 

implementation. 

Response: We are finalizing that 

owners and operators of existing 

affected sources may demonstrate 

compliance by emissions averaging for 

EGUs at the affected source that are 

within a single subcategory and that rely 

on emissions testing as the compliance 

demonstration method. See section VI of 

thie preamble for a fuller discussion. 

J. LEE Criteria 

Comment: A commenter supported 

the LEE provisions but believed one of 

the LEE eligibility criteria should set at 

29.0 lb/year, rather than 22.0 lb/year. 

The commenter suggested 29.0 lb/year 

to be an equally reasonable cut point, 

especially since that value matches the 

low mass emitter Hg monitoring cutoff 

in CAMR and the low mass emitter Hg 

monitoring cutoff that several states 

have adopted, including Illinois, 35 Ill. 

Admin. Code section 225.240(a)(4). 

(See, e.g., Colorado (5 Colo. Code Regs. 

section 1 00 1–8, Reg. No.6, part B, 

Section VIII.B.l0); Michigan (Mich. 

Admin. Code R. 336.2160); Montana 

(Mont. Admin. R. 17.8771(12))). Further, 

a LEE cutoff of 29.0 lb would eliminate 

conflicts and confusion with low mass 

emitter provisions in existing state Hg 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9423 

programs and significantly reduce 

compliance costs and burdens for the 

additional qualifying units without 

adversely affecting compliance 

assurance with the EGU NESHAP Hg 

emission limits or materially increasing 

the number of potential qualifying LEEs. 

Given the many other costly burdens 

that the rule would impose, the benefit 

of LEE to a qualifying unit is not 

insignificant. 

Response: The Agency reviewed the 

commenter’s suggestions, and one of the 

LEE eligibility criteria in the rule has 

been revised from 22.0 to 29.0 lb of Hg 

per year. The Agency finds the result of 

consistency with existing state 

regulations outweighs the two percent 

difference in nationwide Hg mass 

emissions, from 5 percent to 7 percent, 

for LEE eligibility. 

VIII. Background Information on the 

NSPS 

A. What is the statutory authority for 

this final NSPS? 

New source performance standards 

implement CAA section 111(b), and are 

issued for categories of sources which 

cause, or contribute significantly to, air 

pollution which may reasonably be 

anticipated to endanger public health or 

welfare. Section 111 of the CAA 

requires that NSPS reflect the 

application of the best system of 

emissions reductions which (taking into 

consideration the cost of achieving such 

emissions reductions, any non-air 

quality health and environmental 

impact and energy requirements) the 

Administrator determines has been 

adequately demonstrated. The level of 

control prescribed by CAA section 111 

historically has been referred to as ‘‘Best 

Demonstrated Technology’’ or BDT. In 

order to better reflect that CAA section 

111 was amended in 1990 to clarify that 

‘‘best systems’’ may or may not be 

‘‘technology,’’ the EPA is now using the 

term ‘‘best system of emission 

reduction’’ or BSER. As was done 

previously in analyzing BDT, the EPA 

uses available information and 

considers the emission reductions and 

incremental costs for different systems 

available at reasonable cost. Then, the 

EPA determines the appropriate 

emission limits representative of BSER. 

Section 111(b)(1)(B) of the CAA requires 

EPA to periodically review and revise 

the standards of performance, as 

necessary, to reflect improvements in 

methods for reducing emissions. 

B. What is the regulatory authority for 

the final rule? 

The current standards for steam 

generating units are contained in the 

NSPS for EGUs (40 CFR part 60, subpart 

Da), industrial-commercial-institutional 

steam generating units (40 CFR part 60, 

subpart Db), and small industrialcommercial-institutional 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 for EGUs 

also apply to industrial-commercialinstitutional 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 NOP2 limitations for 40 

CFR part 60, subpart Da units. 

The NSPS for industrial-commercialinstitutional steam generating units (40 

CFR part 60, subpart Db) apply to units 

for which construction, modification, or 

reconstruction commenced after June 

19, 1984, that have a heat input capacity 

greater than 29 MW (100 MMBtu/h). 

Those standards were originally 

promulgated on November 25, 1986 (51 

FR 42768) and also have been amended 

since the original promulgation to 

reflect changes in BSER for these 

sources. 

The NSPS for small industrialcommercial-institutional 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 the Final NSPS 

The final rule amends the emission 

standards for SO2, NOP2, and PM in 40 

CFR part 60, subpart Da. Only those 

units that begin construction, 

modification, or reconstruction after 

May 3, 2011, will be affected by the 

final rule. Compliance with the 

emission limits of the final rule will be 

determined using testing, monitoring, 

and other compliance provisions similar 

to those set forth in the existing 

standards. In addition to the emissions 

limits contained in the final rule, we 

also are including several technical 

clarifications and corrections to existing 

provisions of the subparts. 

A. What are the requirements for new 

EGUs (40 CFR part 60, subpart Da)? 

The filterable PM emissions standard 

for new and reconstructed EGUs is 11 

nanograms per joule (ng/J) (0.090 pound 

per megawatt hour (lb/MWh)) gross 

energy output regardless of the type of 

fuel burned. The PM emissions standard 

for modified EGUs is essentially 

equivalent to the existing requirements 

of 13 ng/J (0.015 lb/MWh) heat input 

regardless of the type of fuel burned. 

Compliance with this emission limit can 

be determined using testing, monitoring, 

and other compliance provisions similar 

to those for PM standards set forth in 

the existing rule. While not required, 

PM CEMS may be used as an alternative 

method to demonstrate continuous 

compliance and as an alternative to 

opacity and parameter monitoring 

requirements. 

The SO2 emission limit for new and 

reconstructed EGUs is 130 ng/J (1.0 lb/ 

MWh) gross energy output or 97 percent 

reduction regardless of the type of fuel 

burned with one exception. The EPA 

neither proposed to amended the SO2

standard for coal refuse-fired EGUs, not 

reopened the issue of whether coal 

refuse-fired EGUs is an appropriate 

subcategory, and, therefore, that 

emissions standard is unchanged. The 

SO2 emission limit for modified EGUs 

burning any fuel is 180 ng/J (1.4 lb/ 

MWh) gross energy output or 90 percent 

reduction. Compliance with the SO2

emission limit is determined on a 30- 

boiler operating day rolling average 

basis using a CEMS to measure SO2

emissions and following the compliance 

provisions in the proposed rule. 

The NOX emission limit for new and 

reconstructed EGUs is 88 ng/J (0.70 lb/ 

MWh) gross energy output regardless of 

the type of fuel burned with one 

exception. The exception is that for new 

and reconstructed EGUs that burn over 

75 percent coal refuse (by heat input), 

the NOX emission limit is 110 ng/J (0.85 

lb/MWh) gross energy output. The NOX

limit for modified EGUs is 140 ng/J (1.1 

lb/MWh) gross energy output regardless 

of the type of fuel burned in the unit. 

Compliance with this emission limit is 

determined on a 30-boiler operating day 

rolling average basis using testing, 

monitoring, and other compliance 

provisions similar to those in the 

proposed rule. 

As an alternative to the NOX standard, 

owners/operators of new and 

reconstructed EGUs may elect to comply 

with a combined NOX/CO standard of 

140 ng/J (1.1 lb/MWh) with one 

exception. The exception is that for new 


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9424 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

and reconstructed EGUs that burn over 

75 percent coal refuse (by heat input) on 

an annual basis, the NOX/CO emission 

limit is 160 ng/J (1.3 lb/MWh) gross 

energy output. Finally, owners/ 

operators of modified EGUs may elect to 

comply with a combined NOX/CO 

standard of 190 ng/J (1.5 lb/MWh). 

B. Additional Amendments 

See the Response to Comments 

document. 

X. Summary of Significant Changes 

Since Proposal 

A. Emission Limits 

The proposal included a combined 

(filterable plus condensable) PM 

standard. The final standard is based 

only on filterable PM. No standard is 

being established for condensable PM. 

The rationale for this is set forth in the 

Response to Comments (RTC) document 

for this final rule (the NSPS Final Rule 

RTC). 

The proposal requested comment on 

whether the final standard should 

include a stand-alone NOX standard or 

a combined NOX/CO standard. In 

response to comments we received and 

our own further evaluation of the 

situation, the final standard includes a 

stand-alone NOX standard and an 

optional, but not required, combined 

NOX/CO standard as an alternative to 

the amended NOX standard. Again, our 

full rationale for this is set forth in the 

NSPS Final Rule RTC. The proposal also 

included a request for comment on 

whether the standard should be based 

on gross or net output. In response to 

comments we received and our own 

further evaluation of the situation, the 

final standards are based on an 

amended definition of gross output with 

an optional net output-based standard. 

This too is addressed more fully in the 

NSPS Final Rule RTC. 

The proposal included alternate 

emission standards for commercial 

demonstration projects. Proposed 

commercial demonstrations included 

pressurized fluidized beds, multipollutant control technologies, and 

advanced combustion controls. The 

final rule includes the commercial 

demonstration permit exemption for 

pressurized fluidized beds and multipollutant control technologies, but not 

advanced combustion controls. 

Advanced combustion controls are 

applicable to existing facilities and the 

exemption is not necessary to further 

the development of the technology. 

B. Requirements During Startup, 

Shutdown, and Malfunction 

For startup and shutdown, the 

requirements for PM have changed since 

proposal. For periods of startup and 

shutdown, the EPA is finalizing work 

practice standards for PM in lieu of 

numeric emission limits. Emissions 

incurred during periods of startup and 

shutdown for PM are not used in 

demonstrations of compliance with the 

30-boiler operating day rolling average 

period applicable for numeric emission 

standards. 

XI. Public Comments and Responses to 

the Proposed NSPS 

See the Response to Comments 

document. 

XII. Impacts of the Final Rule 

The EPA anticipates significant public 

health and environmental benefits from 

the rule as a direct result of the 

substantial reduction in the emissions of 

several pollutants, including SO2, Hg, 

acid gases and fine particles and metals. 

For example, exposure to Hg can 

damage the developing nervous system, 

which can impair children’s ability to 

think and learn, and fine particles can 

cause adverse cardiovascular effects. 

Further, reducing Hg deposition to 

ecosystems will benefit wildlife 

including fish, birds, and mammals. 

Fish and fish-eating birds, such as the 

common loon, and mammals suffer 

reproductive, survival, and behavioral 

impairments due to mercury exposure. 

These effects have also been observed in 

insect-eating and wading birds, 

including egrets and white ibis. 

Reductions of emissions targeted by this 

rule also will slow acidification and 

eutrophication of water bodies. 

Additionally, the EPA anticipates 

significant non-health, non-ecological 

benefits from this rule. The fine particle 

and SO2 emission reductions achieved 

by this rule will improve visibility, 

which is especially important for our 

national parks. Emissions reductions 

from this rule will also avoid an 

estimated $360 million (in $2007) of 

climate-related costs, such as 

agricultural productivity and property 

damage from increased flood risks. 

A. What are the air impacts? 

The EPA anticipates significant 

emission reductions under the final rule 

from coal-fired EGUs, which are of 

particular interest due to their share of 

total power sector emissions. In 2015, 

annual HCl emissions are projected to 

be reduced by 88 percent, Hg emissions 

reduced by 75 percent, and PM2.5

emissions reduced by 19 percent from 

coal-fired EGUs greater than 25 MW. In 

addition, the EPA projects SO2 emission 

reductions of 41 percent, and annual 

CO2 reductions of 1 percent from coalfired EGUs greater than 25 MW by 2015, 

relative to the base case. See Table 7. 

TABLE 7—SUMMARY OF EMISSION REDUCTIONS FROM COAL-FIRED EGUS GREATER THAN 25 MW (TPY) 

SO2

(million tons) 

NOX

(million tons) 

Mercury 

(tons) 

HCl 

(thousand tons) 

PM2.5

(thousand tons) 

CO2

(million metric 

tonnes) 

Base Case ........... 3.3 1.7 27 45 270 1,906 

MATS ................... 1.9 1.7 7 6 218 1,882 

Change ................. ¥1.4 0.0 ¥20 ¥40 ¥52 ¥23 

Note: Numbers may not add due to rounding. 

The reductions in this table do not 

account for reductions in other HAP 

which will occur as a result of this rule. 

For instance, the fine particulate 

reductions presented above only partly 

reflect reductions in many heavy metal 

particulates, and the HCl reductions 

above only partly reflect reductions of 

all acid gases. This rule will also result 

in additional HAP reductions from oilfired EGUs, which are covered by the 

rule but are not included in the EPA’s 

analysis of emission reductions. 

B. What are the energy impacts? 

The EPA projects that approximately 

4.7 GW of coal-fired generation (less 

than 2 percent of all coal-fired capacity 

and 0.5 percent of total generation 

capacity in 2015) may be uneconomic to 

maintain and may be removed from 

operation by 2015. These units are 

predominantly smaller, less frequently 

used, and are dispersed throughout the 

country. If current forecasts of either 

natural gas prices or electricity demand 

were revised in the future to be higher, 

that would create a greater incentive to 


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355Numbers 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. 

make further investments in these 

facilities and keep these units 

operational. 

The final rule has other important 

energy market implications. Average 

nationwide retail electricity prices are 

projected to increase in the contiguous 

U.S. by 3.1 percent in 2015. The average 

delivered coal price is projected to 

increase by less than 2 percent in 2015 

as a result of shifts within and across 

coal types. The EPA also projects that 

electric power sector-delivered natural 

gas prices will increase by between 0.3 

and 0.6 percent over the 2015 to 2030 

timeframe, on average, and that natural 

gas use for electricity generation will 

increase by less than 200 billion cubic 

feet (BCF) in 2015. These impacts are 

well within the range of price variability 

that is regularly experienced in natural 

gas markets. Finally, the EPA projects 

coal production for use by the power 

sector, a large component of total coal 

production, will decrease by 10 million 

tons in 2015 from base case levels, 

which is about 1 percent of total coal 

produced for the electric power sector 

in that year. 

C. What are the cost impacts? 

The power industry’s ‘‘compliance 

costs’’ are represented in this analysis as 

the change in electric power generation 

costs between the base case and policy 

case in which the sector pursues 

pollution control approaches to meet 

the MATS emission standards. In 

simple terms, these costs are the 

resource costs of direct power industry 

expenditures to comply with the EPA’s 

requirements. 

The EPA projects that the annual 

incremental compliance cost of MATS 

is $9.6 billion in 2015 ($2007). The 

annualized incremental cost is the 

projected additional cost of complying 

with the rule in the year analyzed, and 

includes the amortized cost of capital 

investment and the ongoing costs of 

operating additional pollution controls, 

needed new capacity, shifts between or 

amongst various fuels, and other actions 

associated with compliance. 

The total incremental compliance cost 

includes compliance costs modeled in 

IPM of $9.4 billion, costs modeled 

outside of IPM for oil-fired EGUs of $56 

million, and monitoring, reporting, and 

recordkeeping costs of $158 million. 

D. What are the economic impacts? 

For this final rule, EPA analyzed the 

costs using the IPM. The IPM is a 

dynamic linear programming model that 

can be used 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/epa-ipm/index.html. 

The EPA performed a screening 

analysis for impacts on small entities by 

comparing compliance costs to sales/ 

revenues (e.g., sales and revenue tests). 

The EPA’s analysis can be found in 

Chapter 7 of the RIA for this rule. The 

EPA has also prepared a Final 

Regulatory Flexibility Analysis (FRFA) 

that discusses alternative regulatory or 

policy options that minimize the rule’s 

small entity impacts. 

Although a stand-alone analysis of 

employment impacts is not included in 

a standard cost-benefit analysis, the 

current economic climate has led to 

heightened concerns about potential job 

impacts. Executive Order 13563 

specifically states that our ‘‘regulatory 

system must protect public health, 

welfare, safety, and our environment 

while promoting economic growth, 

innovation, competitiveness, and job 

creation’’ (emphasis added). 

Under conditions of full employment, 

it is conventional to assume that 

regulations will merely shift jobs from 

one sector to another, without having a 

material effect on employment levels. 

Potential employment effects are of 

greater concern in the current economic 

climate, with high levels of 

employment, because of the risk that 

displaced workers may not find 

alternative jobs. In addition, regulations 

that result in firms hiring workers, in 

order to ensure compliance, may have a 

positive effect on employment. 

During sustained periods of excess 

unemployment, the opportunity cost of 

labor required by regulated sectors to 

bring their facilities into compliance 

with an environmental regulation may 

be lower than it would be during a 

period of full employment (particularly 

if regulated industries employ otherwise 

idled labor to design, fabricate, or install 

the pollution control equipment 

required under this final rule). 

Consistent with EO 13563, the EPA 

includes estimates of job impacts 

associated with the final rule. In the 

electricity sector, the EPA estimates that 

the net employment effect will range 

from ¥15,000 to +30,000 jobs, with a 

central estimate of +8,000. The EPA also 

presents an estimate of short-term 

employment effects as a result of 

increased demand for pollution control 

equipment. 

The results of this analysis, found in 

Chapter 6 of the RIA, indicate that the 

final rule has the potential to provide 

increases in short-term employment in 

the environmental industry, primarily 

driven by the high demand for new 

pollution control equipment. Overall, 

the results suggest that the final rule 

could support a net of roughly 46,000 

job years 355 in direct employment 

impacts in 2015. 

There are other employment effects 

that cannot be estimated quantitatively 

at this time. The employment gains 

related to the new pollution controls are 

likely to be tempered by some losses 

due to certain coal retirements. On the 

other hand, some of those workers who 

lose their jobs due to plant retirements 

could find alternative employment 

operating the replacement electricity 

generating equipment or new pollution 

controls at nearby units. Finally, job 

losses due to reduced coal demand may 

be offset by job gains due to increased 

natural gas demand, potentially 

resulting in a positive net change in 

employment due to fuel demand 

changes. 

The basic approach to estimate these 

employment impacts involved using 

IPM projections from the final rule 

analysis, in particular the amount of 

existing coal-fired capacity that is 

projected to be retrofit with pollution 

control technologies. These data, along 

with data on labor and resource needs 

of new pollution controls and labor 

productivity from engineering studies 

and secondary sources, are used to 

estimate employment impacts for the 

pollution control industry in 2015. For 

more information, please refer to 

Chapter 6 and appendix 6B in the RIA. 

The EPA relied on Morgenstern, et al., 

(2002), to identify three economic 

mechanisms by which pollution 

abatement activities can influence jobs 

in the regulated sector separately from 

the short-term employment effects: 

D Higher production costs raise market 

prices, higher prices reduce 

consumption, and employment within 

an industry falls (‘‘demand effect’’); 

D Pollution abatement activities 

require additional labor services to 

produce the same level of output (‘‘cost 

effect’’); and 

D Post-regulation production 

technologies may be more or less labor 

intensive (i.e., more/less labor is 

required per dollar of output) (‘‘factorshift effect’’). 

Using plant-level Census information 

between the years 1979 and 1991, 


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9426 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

356For alternative views in economic journals, 

see Henderson (1996) and Greenstone (2002). 

357 It should be noted that if more labor must be 

used to produce a given amount of output, then this 

implies a decrease in labor productivity. A decrease 

in labor productivity will cause a short-run 

aggregate supply curve to shift to the left, and 

businesses will produce less, all other things being 

equal. 

Morgenstern,et al., estimate the size of 

each effect for four polluting and 

regulated industries (petroleum, plastic 

material, pulp and paper, and steel). On 

average across the four industries, each 

additional $1 million spent on pollution 

abatement results in a small net increase 

of 1.55 jobs; the estimated effect is not 

a statistically different from zero. As a 

result, the authors conclude that 

increases in pollution abatement 

expenditures may increase employment 

in the relevant sectors and do not 

necessarily cause economically 

significant employment changes. The 

conclusion is similar to that of Berman 

and Bui (2001) who found that 

increased air quality regulation in Los 

Angeles did not cause large employment 

changes.356 For more information, 

please refer to Chapter 6 of the RIA for 

this final rule.357

In the directly affected sector, the EPA 

estimates that the net employment effect 

will range from ¥15,000 to +30,000 

jobs, with a central estimate of +8,000. 

The ranges of job effects for the 

electricity sector, as calculated using the 

Morgenstern,et al., approach are listed 

in Table 8. 

TABLE 8—RANGE OF JOB EFFECTS FOR THE ELECTRICITY SECTOR

Estimates using Morgenstern, et al., (2001) 

Demand effect Cost effect Factor shift 

effect 

Net 

effect 

Change in Full-Time Jobs per Million Dollars of Environmental Expenditure a.¥3.56 .......................... 2.42 ............................. 2.68 ............................. 1.55. 

Standard Error .......................................... 2.03 ............................. 0.83 ............................. 1.35 ............................. 2.24. 

EPA estimate for Final Rule b ................... ¥39,000 to .................

+2,000 .........................

+4,000 to .....................

+21,000 .......................

+200 to ........................

+27,000 .......................

¥15,000 to 

+30,000. 

aExpressed in 1987 dollars. See footnote a from Table 6–2 of the RIA for inflation adjustment factor used in the analysis. bAccording to the 2007 Economic Census, the electric power generation, transmission and distribution sector (NAICS 2211) had approximately 

510,000 paid employees. 

The EPA recognizes there may be 

other job effects that are not considered 

in the Morgenstern,et al., study. 

Although EPA has considered some 

economy-wide changes, we do not have 

sufficient information to quantify other 

job effects associated with this rule. 

E. What are the benefits of this final 

rule? 

1. Benefits of Reducing HAP Emissions 

a. Human Health and Environmental 

Effects Due to Exposure to MeHg. In this 

section, we provide a qualitative 

description of human health and 

environmental effects due to exposure 

to MeHg. The NAS Study (NRC, 2000) 

provides a thorough review of the 

effects of MeHg on human health. Many 

of the peer-reviewed articles cited in 

this section are publications originally 

cited in the NAS Study. In addition, the 

EPA has conducted literature searches 

to obtain other related and more recent 

publications to complement the material 

summarized by the NAS in 2000. 

b. Neurologic Effects of Exposure to 

MeHg. In its review of the literature, the 

NAS found neurodevelopmental effects 

to be the most sensitive and best 

documented endpoints and concluded 

that they are appropriate for establishing 

an RfD (NRC, 2000); in particular NAS 

supported the use of results from 

neurobehavioral or neuropsychological 

tests. The NAS Study (NRC, 2000) noted 

that studies in animals reported sensory 

effects as well as effects on brain 

development and memory functions and 

support the conclusions based on 

epidemiology studies. The NAS noted 

that their recommended 

neurodevelopmental endpoints for an 

RfD are associated with the ability of 

children to learn and to succeed in 

school. They concluded the following: 

‘‘The population at highest risk is the 

children of women who consumed large 

amounts of fish and seafood during 

pregnancy. The committee concludes 

that the risk to that population is likely 

to be sufficient to result in an increase 

in the number of children who have to 

struggle to keep up in school.’’ 

c. Cardiovascular Impacts of Exposure 

to MeHg. The NAS summarized data on 

cardiovascular effects available up to 

2000. Based on these and other studies, 

the NAS Study concluded that 

‘‘Although the data base is not as 

extensive for cardiovascular effects as it 

is for other end points (i.e., neurologic 

effects) the cardiovascular system 

appears to be a target for MeHg toxicity 

in humans and animals.’’ The report 

also stated that ‘‘additional studies are 

needed to better characterize the effect 

of MeHg exposure on blood pressure 

and cardiovascular function at various 

stages of life.’’ 

Additional cardiovascular studies 

have been published since 2000. The 

EPA did not develop a quantitative 

dose-response assessment for 

cardiovascular effects associated with 

MeHg exposures, as there is no 

consensus among scientists on the doseresponse functions for these effects. In 

addition, there is inconsistency among 

available studies as to the association 

between MeHg exposure and various 

cardiovascular system effects. The 

pharmacokinetics of some of the 

exposure measures (such as toenail Hg 

levels) are not well understood. The 

studies have not yet received the review 

and scrutiny of the more wellestablished neurotoxicity data base. 

d. Genotoxic Effects of Exposure to 

MeHg. The Mercury Study noted that 

MeHg is not a potent mutagen but is 

capable of causing chromosomal 

damage in a number of experimental 

systems. The NAS Study indicated that 

evidence that human exposure to MeHg 

causes genetic damage is inconclusive; 

they note that some earlier studies 

showing chromosomal damage in 

lymphocytes may not have controlled 

sufficiently for potential confounders. 

One study of adults living in the 

Tapajo ́ s River region in Brazil 

(Amorimet 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 


srobinson on DSK4SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9427 

358Crump, KL, and Trudeau, VL. Mercuryinduced reproductive impairment in fish. 

Environmental Toxicology and Chemistry. Vol. 28, 

No. 5, 2009. 

359U.S. Environmental Protection Agency (EPA). 

1997. Mercury Study Report to Congress. Volume 

V: Health Effects of Mercury and Mercury 

Compounds. EPA–452/R–97–007. U.S. EPA Office 

of Air Quality Planning and Standards, and Office 

of Research and Development; U.S. Environmental 

Protection Agency (U.S. EPA). 2005. Regulatory 

Impact Analysis of the Final Clean Air Mercury 

Rule. Research Triangle Park, NC., March; EPA 

report no. EPA–452/R–05–003. Available on the 

Internet at http://www.epa.gov/ttn/ecas/regdata/ 

RIAs/mercury_ria_final.pdf. 

360Evers, 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. 

361Adams, 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. 

362Frederick, 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. 

363Sepulveda, 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. 

364Hoffman, 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. 

365Brasso, RL, and Cristol, DA. Effects of mercury 

exposure in the reproductive success of tree 

swallows (Tachycineta bicolor). Ecotoxicology. 

17:133–141, 2008. 

366Hallinger, KK, Cornell, KL, Brasso, RL, and 

Cristol, DA. Mercury exposure and survival in freeliving tree swallows (Tachycineta bicolor). 

Ecotoxicology. Doi: 10.1007/s10646–010–0554–4, 

2010. 

367Hawley, DM, Hallinger, KK, Cristol, DA. 

Compromised immune competence in free-living 

tree swallows exposed to mercury. Ecotoxicology. 

18:499–503, 2009. 

368 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. 

369 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. 

370Scheuhammer, 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. 

seen in the populations studied in the 

Faroe Islands and Republic of 

Seychelles. 

e. Immunotoxic Effects to Exposure to 

MeHg. Although exposure to some 

forms of Hg can result in a decrease in 

immune activity or an autoimmune 

response (ATSDR, 1999), evidence for 

immunotoxic effects of MeHg is limited 

(NRC, 2000). 

f. Other Hg-Related Human Toxicity 

Data. Based on limited human and 

animal data, MeHg is classified as a 

‘‘possible’’ human carcinogen by the 

International Agency for Research on 

Cancer (IARC, 1994) and in IRIS 

(USEPA, 2002). The existing evidence 

supporting the possibility of 

carcinogenic effects in humans from 

low-dose chronic exposures is tenuous. 

Multiple human epidemiological 

studies have found no significant 

association between Hg exposure and 

overall cancer incidence, although a few 

studies have shown an association 

between Hg exposure and specific types 

of cancer incidence (e.g., acute leukemia 

and liver cancer) (NAS, 2000). 

Some evidence of reproductive and 

renal toxicity in humans from MeHg 

exposure exists. However, overall, 

human data regarding reproductive, 

renal, and hematological toxicity from 

MeHg are very limited and are based on 

studies of the two 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 fish 358 reports results for 

numerous species including trout, bass 

(large and smallmouth), northern pike, 

carp, walleye, salmon, and others from 

laboratory and field studies. The effects 

of MeHg in fish are reproductive in 

nature. Although we cannot determine 

at this time whether these reproductive 

deficits are affecting fish populations 

across the U.S. it should be noted that 

it would seem reasonable that over time 

reproductive deficits would have an 

effect on populations. 

Mercury also affects avian species. In 

previous reports 359 much of the focus 

has been on large piscivorous species, in 

particular the common loon. According 

to Evers,et al., significant adverse effects 

from Hg on breeding loons have been 

found to occur, including behavioral 

(reduced nest-sitting), physiological 

(flight feather asymmetry) and 

reproductive (chicks fledged/territorial 

pair) effects and reduced survival.360

Additionally, Evers, et al., (see footnote 

5), believe that the weight of 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. White ibis have been 

observed to have decreased foraging 

efficiency361 and have been shown to 

exhibit decreased reproductive success 

and altered pair behavior.362 In egrets, 

Hg has been implicated in the decline 

of the species in south Florida,363 and 

Hoffman364 has shown that egrets 

exhibit liver and possibly kidney effects. 

Although ibises and egrets are most 

abundant in coastal areas and these 

studies were conducted in south Florida 

and Nevada, the ranges of ibises and 

egrets extend to a large portion of the 

U.S. 

Insectivorous birds have also been 

shown to suffer adverse effects due to 

Hg exposure. Songbirds such as 

Bicknell’s thrush, tree swallows, and the 

great tit have shown reduced 

reproduction, survival, and changes in 

singing behavior. Exposed tree swallows 

produced fewer fledglings,365 had lower 

survival rates,366 and had compromised 

immune competence.367 The great tit 

has exhibited reduced singing behavior 

and smaller song repertoire in areas of 

high contamination.368

In mammals, adverse effects have 

been observed in mink and river otter, 

both fish eating species. For otter from 

Maine and Vermont, maximum 

concentrations of Hg in fur nearly equal 

or exceed a level associated with 

mortality and concentration in liver for 

mink in Massachusetts/Connecticut and 

the levels in fur from mink in Maine 

exceed concentrations associated with 

acute mortality.369 Adverse sublethal 

effects may be associated with lower Hg 

concentrations and consequently may 

be more widespread than potential 

acute effects. These effects may include 

increased activity, poorer maze 

performance, abnormal startle reflex, 

and impaired escape and avoidance 

behavior.370

h. Methodology for Partial Hg Benefits 

Estimation. The EPA has conducted a 

national-scale analysis of the benefits to 

recreational anglers of avoided IQ loss 

related to reductions of Hg emissions 


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9428 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

371Monetized 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 

Mercury Maps approach does not provide any 

information on the time lag of response. 

372Roman, 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. 

and subsequent deposition that will be 

achieved by this rule. Because the 

primary measurable health effect of 

concern—developmental neurological 

abnormalities in children—occurs as a 

result of in-utero exposures to Hg, the 

specific population of interest in this 

case is prenatally exposed children. To 

identify and estimate the size of this 

exposed population, the benefits 

analysis focused on pregnant women in 

freshwater recreational angler 

households. Estimating Hg exposures 

for this exposure pathway and 

population of interest requires three 

main components: (1) The size of the 

exposed population of interest (annual 

number of pregnant women in 

freshwater angler households during the 

year), (2) the average concentration of 

MeHg in noncommercial freshwater fish 

filets consumed, and (3) the average 

daily consumption rate of 

noncommercial freshwater fish. The Hg 

concentrations of fish in the 

waterbodies where the fish are caught 

are modeled using Mercury Maps to 

project the decline in concentrations 

due to the rule. To approximate the 

percentage of freshwater fishing trips 

(and exposed individuals) from each 

Census tract matched to each waterbody 

type, the EPA used state-level averages. 

These averages were calculated for each 

state, based on the portion of residents’ 

freshwater fishing trips that are to each 

waterbody type, based on 2001 National 

Survey of Fishing, Hunting, and 

Wildlife-Associated Recreation 

(FHWAR) data. 

Data from the 1994 National Survey 

on Recreation and the Environment 

(NSRE) were used to approximate the 

percentage of freshwater fishing trips 

(and exposed individuals) matched to 

different distances from anglers’ 

residential location. 

To determine an appropriate daily 

fish consumption rate for the analysis, 

the EPA conducted an extensive review 

of existing literature characterizing selfcaught freshwater fish consumption. 

Based on this review, it was decided 

that the ingestion rates for recreational 

freshwater fishers, specified as 

‘‘recommended’’ in the EPA’s 

‘‘Environmental Exposure Factors 

Handbook’’ (EPA, 1997), represented the 

most appropriate values to use in this 

analysis. 

Estimating the IQ decrements in 

children that result from mothers’ 

prenatal ingestion of Hg from fish 

required two steps. First, based on the 

estimated average daily maternal 

ingestion rate, the expected Hg 

concentration in the hair of exposed 

pregnant women was estimated. 

Second, to estimate the expected IQ 

decrement in offspring, the following 

dose-response relationship was 

developed based on the summary 

findings reported in Axelrad et al., 

(2007). 

The valuation approach used to assess 

monetary losses due to IQ decrements is 

based on an approach applied in 

previous EPA analyses (EPA, 2008). The 

approach expresses the potential loss to 

an affected individual resulting from IQ 

decrements in terms of foregone future 

earnings (net of changes in education 

costs) for that individual. 

The estimate for ‘‘Present Value of 

Lifetime Earnings’’ is derived using 

earnings and labor force participation 

rate data from the Bureau of Labor 

Statistics 2006 Current Population 

Survey. Estimates of the average effect 

of a 1-point increase in IQ on lifetime 

earnings range from a 1.76 percent 

increase (Schwartz, 1994) to a 2.379 

percent increase (Salkever, 1995). The 

percentage increases in the two studies 

reflect both the direct impact of IQ on 

hourly wages and indirect effects on 

annual earnings as the result of 

additional schooling and increased 

labor force participation. The estimate 

for years of additional schooling is 

based on Schwartz (1994), who reports 

an increase of 0.131 years of schooling 

per IQ point. 

In addition to this positive net effect 

on earnings, an increase in IQ is also 

assumed to have a positive effect on the 

amount of time spent in school and on 

associated costs. To incorporate (1) 

uncertainty regarding the size of the 

percentage change in future earnings 

and (2) different assumptions regarding 

the discount rate, the resulting value 

estimates for the average net loss per IQ 

point decrement are expressed as a 

range. Assuming a 3 percent discount 

rate, value IQ ranges from $8,013 (using 

the Schwartz estimates) to $11,859 

(using the Salkever estimates) in 

increased earnings per year per 1-point 

IQ increase. With a 7 percent discount 

rate assumption, the value IQ estimates 

range from $893 to $1,958 in increased 

earnings per year per 1-point IQ 

increase. 

The EPA analyzed the aggregate 

national IQ and present-value loss 

estimates for two base case and three 

emission control scenarios. The highest 

losses are estimated for the 2005 base 

case. For the population of prenatally 

exposed children included in the 

analysis (almost 240,000), Hg exposures 

under baseline conditions during the 

year 2005 are estimated to have resulted 

in more than 25,500 IQ points lost. 

Assuming a 3 percent discount rate, the 

present-year value of these losses ranges 

from $204.8 million to $292.5 million 

nationally.371 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-year value range is considerably 

lower: $22.8 million to $50.0 million. 

For this rule, the EPA generated 

estimates of aggregate nationwide 

benefits associated with reductions in 

Hg exposures and resulting reductions 

in IQ losses. Most importantly, the 

benefits of the 2016 MATS scenario 

(relative to the 2016 base case) are 

estimated to range between $4 million 

and $6 million (assuming a 3 percent 

discount rate), because of an estimated 

511 point reduction in IQ losses. The 

EPA recognizes that these calculated 

benefits are a small subset of the 

benefits of reducing Hg emissions. 

2. Health and Welfare Co-Benefits 

Emission controls installed to meet 

the requirements of this rule will 

generate co-benefits by reducing criteria 

pollutants including PM2.5 and SO2, as 

well as CO2. For this rule, we were only 

able to estimate the mortality benefits of 

PM2.5 reductions due to changes in 

emissions of SO2 and direct PM2.5 and 

climate benefits resulting from CO2

reductions. Additional co-benefits may 

result from decreases in PM2.5 morbidity 

impacts, decreases in sulfur deposition 

and direct health effects of SO2, and 

improvements in visibility in national 

parks and wilderness areas. Total cobenefits may be higher than the partial 

estimates of co-benefits provided here. 

Our best estimate of the monetized 

health and climate co-benefits of this 

rule in 2016 at a 3 percent discount rate 

are $37 billion to $90 billion or $33 

billion to $81 billion at a 7 percent 

discount rate (2007$). Using alternate 

relationships between PM2.5 and 

premature mortality supplied by 

experts, higher and lower health cobenefits estimates are plausible, but 

most of the expert-based estimates fall 

between these two estimates.372

a. Human Health Co-Benefits. To 

estimate the human health co-benefits of 

this rule, the EPA used benefit-per-ton 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9429 

373Fann, 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. 

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 benefitper-ton factors were based on an interim 

baseline and policy scenario for which 

full-scale ambient air quality modeling 

and air quality-based human health 

benefits assessments were performed. 

This general approach and methodology 

is laid out in Fann, et al., (2009),373 but 

for this rule the air quality modeling 

used a better spatial representation of 

the emission changes from EGUs. Using 

a benefit-per-ton approach adds another 

important source of uncertainty to the 

benefits estimates. For more details on 

the creation of the benefit-per-ton 

factors and their application to emission 

reductions under this rule, please refer 

to the RIA for this rule in the docket. 

Table 9 presents the estimates of 

reduced annual incidence of PM2.5- 

related health effects in 2016 resulting 

from this rule. Table 10 presents the 

estimated annual monetary value of the 

reduced incidence of quantified health 

endpoints in 2016 resulting from this 

rule. 

The reduction in premature fatalities 

each year accounts for between 93 and 

97 percent of the estimated health cobenefits that were monetized. 

TABLE 9—ESTIMATED REDUCTIONS IN INCIDENCE OF PM2.5-RELATED HEALTH EFFECTS IN 2016 a

Health effect Number of reduced cases 

Adult Premature Mortality 

Pope et al., (2002) (age >30) ......................................................................................................................... 4,200. 

(1,200 to 7,200). 

Laden et al., (2006) (age >25) ....................................................................................................................... 11,000. 

(5,000 to 17,000). 

Infant Premature Mortality (<1 year) ..................................................................................................................... 20. 

(¥22 to 61). 

Chronic Bronchitis .................................................................................................................................................. 2,800. 

(88 to 5,600). 

Non-fatal heart attacks (age >18) ......................................................................................................................... 4,700. 

(1,200 to 8,300). 

Hospital admissions—respiratory (all ages) .......................................................................................................... 830. 

(330 to 1,300). 

Hospital admissions—cardiovascular (age >18) ................................................................................................... 1,800. 

(1,200 to 2,200). 

Emergency room visits for asthma (age <18) ....................................................................................................... 3,100. 

(1,600 to 4,700). 

Acute bronchitis (age 8–12) .................................................................................................................................. 6,300. 

(¥1,400 to 14,000). 

Lower respiratory symptoms (age 7–14) ............................................................................................................... 80,000. 

(31,000 to 130,000). 

Upper respiratory symptoms (asthmatics age 9–11) ............................................................................................ 60,000. 

(11,000 to 110,000). 

Asthma exacerbation (asthmatics 6–18) ............................................................................................................... 130,000. 

(4,500 to 450,000). 

Lost work days (ages 18–65) ................................................................................................................................ 540,000. 

(460,000 to 620,000). 

Minor restricted-activity days (ages 18–65) .......................................................................................................... 3,200,000. 

(2,600,000 to 3,800,000). 

aValues 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 2016 a

Health effect Monetized benefits 

Adult Premature Mortality 

Pope, et al., (2002) (age >30): 

3% discount rate ............................................................................................................................................. $34. 

($2.6 to $100). 

7% discount rate ............................................................................................................................................. $30. 

($2.4 to $92). 

Laden, et al., (2006) (age >25): 

3% discount rate ............................................................................................................................................. $87. 

($7.5 to $250). 

7% discount rate ............................................................................................................................................. $78. 

($6.8 to $230). 

Infant Premature Mortality (<1 year) ..................................................................................................................... $0.2. 

($¥0.2 to $0.8). 

Chronic Bronchitis .................................................................................................................................................. $1.4. 

($0.1 to $6.4). 

Non-fatal heart attacks (age >18): 


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9430 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

374Pope 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. 

375Ladenet al., 2006. ‘‘Reduction in Fine 

Particulate Air Pollution and Mortality.’’ American 

Journal of Respiratory and Critical Care Medicine. 

173:667–672. 

TABLE 10—ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-RELATED HEALTH BENEFITS IN 2016 a—Continued 

Health effect Monetized benefits 

3% discount rate ............................................................................................................................................. $0.5. 

($0.1 to $1.3). 

7% discount rate ............................................................................................................................................. $0.4. 

($0.1 to $1.0). 

Hospital admissions—respiratory (all ages) .......................................................................................................... $0.01. 

($0.01 to $0.02). 

Hospital admissions—cardiovascular (age >18) ................................................................................................... $0.03. 

(<$0.01 to $0.05). 

Emergency room visits for asthma (age <18) ....................................................................................................... <$0.01. 

Acute bronchitis (age 8–12) .................................................................................................................................. <$0.01. 

Lower respiratory symptoms (age 7–14) ............................................................................................................... <$0.01. 

Upper respiratory symptoms (asthmatics age 9–11) ............................................................................................ <$0.01. 

Asthma exacerbation (asthmatics 6–18) ............................................................................................................... <$0.01. 

Lost work days (ages 18–65) ................................................................................................................................ $0.1. 

($0.1 to $0.1). 

Minor restricted-activity days (ages 18–65) .......................................................................................................... $0.2. 

($0.1 to $0.3). 

Monetized Health Co-Benefits 

Pope, et al., (2002): 

3% discount rate ............................................................................................................................................. $36. 

($2.8–$110). 

7% discount rate ............................................................................................................................................. $33. 

($2.5–$100). 

Laden, et al., (2006): 

3% discount rate ............................................................................................................................................. $89. 

($7.7–$260). 

7% discount rate ............................................................................................................................................. $80. 

($6.9–$240). 

aValues 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 co-benefits is 

largely driven by the concentration 

response function for premature 

mortality. Experts have advised the EPA 

to consider a variety of assumptions, 

including estimates based both on 

empirical (epidemiological) studies and 

judgments elicited from scientific 

experts, to characterize the uncertainty 

in the relationship between PM2.5

concentrations and premature mortality. 

We cite two key empirical studies, one 

based on the American Cancer Society 

cohort study 374 and the other based on 

the extended Six Cities cohort study.375

The analyses upon which this rule is 

based were selected from the peerreviewed scientific literature. We used 

up-to-date assessment tools, and we 

believe the results are highly useful in 

assessing this rule. 

Every benefit analysis examining the 

potential effects of a change in 

environmental protection requirements 

is limited to some extent by data gaps, 

model capabilities (such as geographic 

coverage), and uncertainties in the 

underlying scientific and economic 

studies used to configure the benefit and 

cost models. Gaps in the scientific 

literature often result in the inability to 

estimate quantitative changes in health 

and environmental effects, or to assign 

economic values even to those health 

and environmental outcomes that can be 

quantified. The uncertainties in the 

underlying scientific and economics 

literature (that may result in 

overestimation or underestimation of 

the co-benefits) are discussed in detail 

in the RIA. Despite these uncertainties, 

we believe the benefit analysis for this 

rule provides a reasonable indication of 

the expected health co-benefits of the 

rulemaking in future years under a set 

of reasonable assumptions. 

When characterizing uncertainty in 

the PM-mortality relationship, the EPA 

has historically presented a sensitivity 

analysis applying alternate assumed 

thresholds in the PM concentrationresponse 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 no-threshold log-linear 

model most adequately portrays the PMmortality concentration-response 

relationship. 

In the RIA accompanying this 

rulemaking, rather than segmenting out 

impacts predicted to be associated with 

levels above and below a ‘‘bright line’’ 

threshold, the EPA includes a ‘‘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 PMrelated mortality benefits occurring 

above or below the LML of each study; 

in general, our confidence in the size of 

the estimated reduction in PM2.5-related 

premature mortality diminishes as 

baseline concentrations of PM2.5 are 

lowered. 

Based on the modeled interim 

baseline which is approximately 

equivalent to the final baseline (see 

Appendix A of the RIA), 11 percent and 

73 percent of the estimated avoided 

mortality impacts occur at or above an 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9431 

376 Docket ID EPA–HQ–OAR–2009–0472–114577, 

Technical Support Document: Social Cost of Carbon 

for Regulatory Impact Analysis Under Executive 

Order 12866, Interagency Working Group on Social 

Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental 

Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of 

Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and 

Climate Change, Office of Management and Budget, 

Office of Science and Technology Policy, and 

Department of Treasury (February 2010). Also 

available at http://epa.gov/otaq/climate/ 

regulations.htm. 

annual mean PM2.5 level of 10 mg/m3 

(the LML of the Ladenet al., 2006 

study)or 7.5 mg/m3 (the LML of the 

Pope,et al., 2002 study), respectively. 

Although the LML analysis provides 

some insight into the level of 

uncertainty in the estimated PM 

mortality benefits, the EPA does not 

view the LML as a threshold and 

continues to quantify PM-related 

mortality impacts using a full range of 

modeled air quality concentrations. A 

large fraction of the PM2.5-related 

benefits occur below the level of the 

National Ambient Air Quality Standard 

(NAAQS) for PM2.5 at 15 mg/m3, which 

was set in 2006. It is important to 

emphasize that NAAQS are not set at a 

level of zero risk. Instead, the NAAQS 

reflect the level determined by the 

Administrator to be protective of public 

health within an adequate margin of 

safety, taking into consideration effects 

on susceptible populations. While 

benefits occurring below the standard 

may be less certain than those occurring 

above the standard, EPA considers them 

to be legitimate components of the total 

benefits estimate. 

It is important to note that the 

monetized benefits include many but 

not all health effects associated with 

PM2.5 exposure. Benefits are shown as a 

range from Pope, et al., (2002), to Laden, 

et al., (2006). These studies assume that 

all fine particles, regardless of their 

chemical composition, are equally 

potent in causing premature mortality 

because there is no clear scientific 

evidence that would support the 

development of differential effects 

estimates by particle type. Even though 

we assume that all fine particles have 

equivalent health effects, the benefitper-ton estimates vary between directlyemitted particles (carbonaceous and 

crustal particles) and SO2 emissions that 

form sulfate particles, based on the 

location of emission changes and 

magnitude of population exposure 

changes. Regardless, however, the 

assumption that all fine particles are 

equally potent in causing premature 

mortality adds uncertainty to the 

benefits estimate. 

b. Non-Climate Welfare Co-Benefits. 

Emission controls installed to comply 

with the requirements specified in this 

rule will also generate co-benefits by 

improving visibility. We anticipate that 

improvements in visibility in Class I 

areas as well as residential areas where 

people live, work, and recreate could be 

substantial. Because full-scale air 

quality modeling was not performed for 

this rule, we are unable to quantify 

these visibility co-benefits for this rule. 

However, the estimated value of 

visibility benefits calculated from the 

modeled interim baseline and policy 

scenario was $1.1 billion (in 2007$). 

These visibility benefits are not 

included in the total co-benefits 

estimate of the final policy scenario 

used as a basis for this final rule. The 

distribution of emission reductions did 

not change substantially in the visibility 

regions studied, therefore visibility 

benefits of the final policy scenario are 

likely to be of a similar magnitude. 

Ecosystem and other welfare effects 

include reduced acidification and, in 

the case of NOX, eutrophication of water 

bodies; possible reduced nitrate 

contamination of drinking water; ozone 

vegetation damage; a reduction in the 

role of sulfate in Hg methylation; and 

reduced acid and particulate deposition 

that causes damages to cultural 

monuments, as well as soiling and other 

materials damage. To illustrate the 

important nature of benefit categories 

the EPA is currently unable to monetize, 

we discuss the potential public welfare 

and environmental impacts related to 

reductions in emissions required by this 

rule in the RIA, including reduced 

visibility impairment, reduced effects 

from acid deposition, reduced effects 

from nutrient enrichment, and reduced 

vegetation effects from ambient 

exposure to SO2 and NO2. 

c. Climate co-benefits. This rule is 

expected to reduce CO2 emissions from 

the electricity sector. The EPA has 

assigned a dollar value to reductions in 

CO2 emissions using recent estimates of 

the ‘‘social cost of carbon’’ (SCC). The 

SCC is an estimate of the monetized 

damages associated with an incremental 

increase in carbon emissions in a given 

year or the per metric ton benefit 

estimate relating to decreases in CO2

emissions. It is intended to include (but 

is not limited to) changes in net 

agricultural productivity, human health, 

property damage from increased flood 

risk, and the value of ecosystem services 

due to climate change. 

The SCC estimates used in this 

analysis were developed through an 

interagency process that included the 

EPA and other executive branch 

entities, and that concluded in February 

2010. We first used these SCC estimates 

in the benefits analysis for the final joint 

EPA/DOT Rulemaking to establish 

Light-Duty Vehicle Greenhouse Gas 

Emission Standards and Corporate 

Average Fuel Economy Standards; see 

the rule’s preamble for discussion about 

application of the SCC (75 FR 25324; 

May 7, 2010). The SCC Technical 

Support Document (SCC TSD) provides 

a complete discussion of the methods 

used to develop these SCC estimates.376

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 values at a 3 percent 

discount rate. It is included to represent 

higher-than-expected impacts from 

temperature change further out in the 

extremes of the SCC distribution. Low 

probability, high impact events are 

incorporated into all of the SCC values 

through explicit consideration of their 

effects in two of the three values as well 

as the use of a probability density 

function for equilibrium climate 

sensitivity. Treating climate sensitivity 

probabilistically results in more high 

temperature outcomes, which in turn 

leads to higher projections of damages. 

Applying the global SCC estimates 

using a 3 percent discount rate, we 

estimate the value of the climate related 

benefits of this rule in 2016 is $360 

million (2007$), as shown in Table 11. 

See the RIA for more detail on the 

methodology used to calculate these 

benefits and additional estimates of 

climate benefits using different discount 

rates and the 95th percentile of the 3 

percent discount rate SCC. Important 

limitations and uncertainties of the SCC 

approach are also described in the RIA. 


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9432 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

TABLE 11—ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-RELATED HEALTH BENEFITS AND CLIMATE

BENEFITS IN 2016a

Effect Monetized benefits 

Monetized Health Co-Benefits 

Pope, et al., (2002): 

3% discount rate ........................................................................................................................................................... $36 

($2.8–$110) 

7% discount rate ........................................................................................................................................................... $33 

($2.5–$100) 

Laden, et al., (2006): ........................................

3% discount rate ........................................................................................................................................................... $89 

($7.7–$260) 

7% discount rate ........................................................................................................................................................... $80 

($6.9–$240) 

Climate-related Co-Benefits (3% discount rate) .................................................................................................................. $0.36 

Monetized Total Co-Benefits 

Pope, et al., (2002): ........................................

3% discount rate ........................................................................................................................................................... $37 

($3.2–$110) 

7% discount rate ........................................................................................................................................................... $33 

($2.9–$100) 

Laden, et al., (2006): ........................................

3% discount rate ........................................................................................................................................................... $90 

($8.0–$260) 

7% discount rate ........................................................................................................................................................... $81 

($7.3–$240) 

aValues rounded to two significant figures. Co-benefits from reducing exposure to ozone, other criteria pollutants, and HAP, as well as reducing visibility impairment and ecosystem effects are not included here. 

Our best estimate for the monetized 

total health and climate co-benefits of 

this rule in 2016 at a 3 percent discount 

rate is between $37 billion and $90 

billion or between $33 billion and $81 

billion (2007$) at a 7 percent discount 

rate. These estimates account for the 

quantified health and climate benefits 

described in Table 11. 

XIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866, Regulatory 

Planning and Review and Executive 

Order 13563, Improving Regulation and 

Regulatory Review 

Under EO 12866 (58 FR 51735; 

October 4, 1993), this action is an 

‘‘economically significant regulatory 

action’’ because it is likely to have an 

annual effect on the economy of $100 

million or more or adversely affect in a 

material way the economy, a sector of 

the economy, productivity, competition, 

jobs, the environment, public health or 

safety, or state, local, or tribal 

governments or communities. 

Accordingly, the EPA submitted this 

action to the OMB for review under 

Executive Orders 12866 and 13563 and 

any changes in response to OMB 

recommendations have been 

documented in the docket for this 

action. For more information on the 

costs and benefits for this rule, please 

refer to Table 2 of this preamble. 

When estimating the human health 

benefits and compliance costs in Table 

2 of this preamble, the EPA applied 

methods and assumptions consistent 

with the state-of-the-science for human 

health impact assessment, economics 

and air quality analysis. The EPA 

applied its best professional judgment 

in performing this analysis and believes 

that these estimates provide a 

reasonable indication of the expected 

benefits and costs to the nation of this 

rulemaking. The RIA available in the 

docket describes in detail the empirical 

basis for the EPA’s assumptions and 

characterizes the various sources of 

uncertainties affecting the estimates 

below. In doing what is laid out above 

in this paragraph, the EPA adheres to 

EO 13563, ‘‘Improving Regulation and 

Regulatory Review,’’ (76 FR 3821; 

January 18, 2011), which is a 

supplement to EO 12866. 

In addition to estimating costs and 

benefits, EO 13563 focuses on the 

importance of a ‘‘regulatory system 

[that] * * * promote[s] predictability 

and reduce[s] uncertainty’’ and that 

‘‘identify[ies] and use[s] the best, most 

innovative, and least burdensome tools 

for achieving regulatory ends.’’ In 

addition, EO 13563 states that ‘‘[i]n 

developing regulatory actions and 

identifying appropriate approaches, 

each agency shall attempt to promote 

such coordination, simplification, and 

harmonization. Each agency shall also 

seek to identify, as appropriate, means 

to achieve regulatory goals that are 

designed to promote innovation.’’ We 

recognize that the utility sector faces a 

variety of requirements, including ones 

under CAA section 110(a)(2)(D) dealing 

with the interstate transport of 

emissions contributing to ozone and PM 

air quality problems, with coal 

combustion wastes, and with the 

implementation of CWA section 316(b). 

In developing today’s final rule, the EPA 

recognizes that it needs to approach 

these rulemakings in ways that allow 

the industry to make practical 

investment decisions that minimize 

costs in complying with all of the final 

rules, while still achieving the 

fundamentally important environmental 

and public health benefits that underlie 

the rulemakings. 

A summary of the monetized costs, 

benefits, and net benefits for the final 

rule at discount rates of 3 percent and 

7 percent is in Table 2 of this preamble. 

For more information on the analysis, 

please refer to the RIA for this 

rulemaking, which is available in the 

docket. 

B. Paperwork Reduction Act 

The information collection 

requirements in this rule have been 

submitted for approval to the OMB 

under the Paperwork Reduction Act, 44 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9433 

U.S.C. 3501 et seq. The Information 

Collection Request (ICR) document 

prepared by the EPA has been assigned 

EPA ICR number 2137.06. 

The information collection 

requirements are not enforceable until 

OMB approves them. The information 

requirements are based on notification, 

recordkeeping, and reporting 

requirements in the NESHAP General 

Provisions (40 CFR part 63, subpart A), 

which are mandatory for all operators 

subject to national emission standards. 

These recordkeeping and reporting 

requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). 

All information submitted to the EPA 

pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to Agency 

policies set forth in 40 CFR part 2, 

subpart B. This final rule requires 

maintenance inspections of the control 

devices but would not require any 

notifications or reports beyond those 

required by the General Provisions. The 

recordkeeping requirements require 

only the specific information needed to 

determine compliance. 

When a malfunction occurs, sources 

must report them according to the 

applicable reporting requirements of 40 

CFR part 63, subpart UUUUU. An 

affirmative defense to civil penalties for 

exceedances of emission limits that are 

caused by malfunctions is available to a 

source if it can demonstrate that certain 

criteria and requirements are satisfied. 

The criteria ensure that the affirmative 

defense is available only where the 

event that causes an exceedance of the 

emission limit meets the narrow 

definition of malfunction in 40 CFR 63.2 

(sudden, infrequent, not reasonable 

preventable, and not caused by poor 

maintenance and or careless operation) 

and where the source took necessary 

actions to minimize emissions. In 

addition, the source must meet certain 

notification and reporting requirements. 

For example, the source must prepare a 

written root cause analysis and submit 

a written report to the Administrator 

documenting that it has met the 

conditions and requirements for 

assertion of the affirmative defense. 

For this rule, EPA is adding 

affirmative defense to the estimate of 

burden in the ICR. To provide the 

public with an estimate of the relative 

magnitude of the burden associated 

with an assertion of the affirmative 

defense position adopted by a source, 

the EPA has provided administrative 

adjustments to this ICR that shows what 

the notification, recordkeeping, and 

reporting requirements associated with 

the assertion of the affirmative defense 

might entail. The EPA’s estimate for the 

required notification, reports, and 

records, including the root cause 

analysis, associated with a single 

incident totals approximately totals 

$3,141, and is based on the time and 

effort required of a source to review 

relevant data, interview plant 

employees, and document the events 

surrounding a malfunction that has 

caused an exceedance of an emission 

limit. The estimate also includes time to 

produce and retain the record and 

reports for submission to EPA. The EPA 

provides this illustrative estimate of this 

burden, because these costs are only 

incurred if there has been a violation, 

and a source chooses to take advantage 

of the affirmative defense. 

The EPA provides this illustrative 

estimate of this burden because these 

costs are only incurred if there has been 

a violation and a source chooses to take 

advantage of the affirmative defense. 

Given the variety of circumstances 

under which malfunctions could occur, 

as well as differences among sources’ 

operation and maintenance practices, 

we cannot reliably predict the severity 

and frequency of malfunction-related 

excess emissions events for a particular 

source. It is important to note that the 

EPA has no basis currently for 

estimating the number of malfunctions 

that would qualify for an affirmative 

defense. Current historical records 

would be an inappropriate basis, as 

source owners or operators previously 

operated their facilities in recognition 

that they were exempt from the 

requirement to comply with emissions 

standards during malfunctions. Of the 

number of excess emissions events 

reported by source operators, only a 

small number would be expected to 

result from a malfunction (based on the 

definition above), and only a subset of 

excess emissions caused by 

malfunctions would result in the source 

choosing to assert the affirmative 

defense. Thus, we believe the number of 

instances in which source operators 

might be expected to avail themselves of 

the affirmative defense will be 

extremely small. 

For this reason, we estimate no more 

than two such occurrences for all 

sources subject to 40 CFR part 63, 

subpart UUUUU over the 3-year period 

covered by this ICR. We expect to gather 

information on such events in the 

future, and will revise this estimate as 

better information becomes available. 

The annual monitoring, reporting, and 

record-keeping burden for this 

collection (averaged over the first 3 

years after the effective date of the 

standards) is estimated to be $207.6 

million. This includes 700,296 labor 

hours per year at a total labor cost of 

$49.1 million per year, annualized 

capital costs of $81.9 million, and 

annual operating and maintenance costs 

of $76.5 million. This estimate includes 

initial and annual performance tests, 

semiannual excess emission reports, 

developing a monitoring plan, 

notifications, and recordkeeping. All 

burden estimates are in 2007 dollars and 

represent the most cost effective 

monitoring approach for affected 

facilities. Burden is defined at 5 CFR 

1320.3(b). 

An Agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for our regulations are listed in 

40 CFR part 9. When this ICR is 

approved by OMB, the Agency will 

publish a technical amendment to 40 

CFR part 9 in the Federal Register to 

display the OMB control number for the 

approved information collection 

requirements contained in this final 

rule. 

C. Regulatory Flexibility Act, as 

Amended by the Small Business 

Regulatory Enforcement Fairness Act of 

1996 (SBREFA), 5 U.S.C. 601 et seq. 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the 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 


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9434 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

and recommendations of representatives 

of the regulated small entities. A 

detailed discussion of the Panel’s advice 

and recommendations is found in the 

Panel Report (EPA–HQ–OAR–2009– 

0234–2921). A summary of the Panel’s 

recommendations is presented at 76 FR 

24975. 

As required by RFA section 604, we 

also prepared a final regulatory 

flexibility analysis (FRFA) for the final 

rule. The FRFA addresses the issues 

raised by public comments on the IRFA, 

which was part of the proposal of this 

rule. The FRFA is summarized below 

and in the RIA. 

1. Reasons Why Action Is Being Taken 

In 2000, the EPA made a finding that 

it was appropriate and necessary to 

regulate coal- and oil-fired EGUs under 

CAA section 112 and listed EGUs 

pursuant to CAA section 112(c). On 

March 29, 2005 (70 FR 15994), the EPA 

published a final rule (2005 Action) that 

removed EGUs from the list of sources 

for which regulation under CAA section 

112 was required. That rule was 

published in conjunction with a rule 

requiring reductions in emissions of Hg 

from EGUs pursuant to CAA section 

111, i.e., CAMR, May 18, 2005, 70 FR 

28606). The 2005 Action was vacated on 

February 8, 2008, by the U.S. Court of 

Appeals for the District of Columbia 

Circuit. As a result of that vacatur, 

CAMR was also vacated and EGUs 

remain on the list of sources that must 

be regulated under CAA section 112. 

This action provides the EPA’s final 

NESHAP and NSPS for EGUs. 

2. Statement of Objectives and Legal 

Basis for Final Rules 

The MATS will protect air quality and 

promote public health by reducing 

emissions of HAP. In the December 

2000 regulatory determination, the EPA 

made a finding that it was appropriate 

and necessary to regulate EGUs under 

CAA section 112. The February 2008 

vacatur of the 2005 Action reverted the 

status of the rule to the December 2000 

regulatory determination. Section 

112(n)(1)(A) of the CAA and the 2000 

determination do not differentiate 

between EGUs located at major versus 

area sources of HAP. Thus, the NESHAP 

for EGUs will regulate units at both 

major and area sources. Major sources of 

HAP are those that have the potential to 

emit at least 10 tons per year (tpy) of 

any one HAP or at least 25 tpy of any 

combination of HAP. Area sources are 

any stationary sources of HAP that are 

not major sources. 

3. Summary of Issues Raised During the 

Public Comment Process on the IRFA 

The EPA received a number of 

comments related to the Regulatory 

Flexibility Act during the public 

comment process. A consolidated 

version of the comments received is 

reproduced below. These comments can 

also be found in their entirety in the 

response to comment document in the 

docket. 

Comment: Several commenters 

expressed concern with the SBAR 

panel. Some believe Small Entity 

Representatives (SERs) were not 

provided with regulatory alternatives 

including descriptions of significant 

regulatory options, differing timetables, 

or simplifications of compliance and 

reporting requirements, and 

subsequently were not presented with 

an opportunity to respond. One 

commenter believes the EPA’s formal 

SBAR Panel notification and subsequent 

information provided by the EPA to the 

Panel did not include information on 

the potential impacts of the rule as 

required by CAA section 609(b)(1). 

Additional commenters suggested that 

the EPA’s rulemaking schedule put 

pressure on the SBAR Panel through the 

abbreviated preparation for the Panel. 

Commenters also expressed concerns 

that the EPA did not provide 

participants more than cursory 

background information on which to 

base their comments. One commenter 

stated that the EPA did not provide 

deliberative materials, including draft 

proposed rules or discussions of 

regulatory alternatives, to the SBAR 

Panel members. One commenter stated 

the SBAR Panel Report does not meet 

the statutory obligation to recommend 

less burdensome alternatives. The 

commenter suggested the EPA panel 

members declined to make 

recommendations that went further than 

consideration or investigation of broad 

regulatory alternatives, with the 

exception of those recommendations in 

which the EPA rejected alternative 

interpretations of the CAA section 112 

and relevant court cases. Two stated 

that the EPA did not respond to the 

concerns of the small business 

community, the SBA, or OMB, ignoring 

concerns expressed by the SER 

panelists. One commenter believes the 

EPA failed to convene required 

meetings and hearings with affected 

parties as required by law for small 

business entities. One commenter stated 

that the SERs’ input is very important 

because more than 90 percent of public 

power utility systems meet the 

definition and qualify as small 

businesses under the SBREFA. 

Response: The RFA requires that 

SBAR Panels collect advice and 

recommendations from SERs on the 

issues related to: 

—The number and description of the 

small entities to which the proposed 

rule will apply; 

—The projected reporting, 

recordkeeping and other compliance 

requirements of the proposed rule; 

—Duplication, overlap or conflict 

between the proposed rule and other 

federal rules; and 

—Alternatives to the proposed rule that 

accomplish the stated statutory 

objectives and minimize any 

significant economic impact on small 

entities. 

The RFA does not require a covered 

agency to create or assemble 

information for SERs or for the 

government panel members. Although 

CAA section 609(b)(4) requires that the 

government Panel members review any 

material the covered agency has 

prepared in connection with the RFA, 

the law does not prescribe the materials 

to be reviewed. The EPA’s policy, as 

reflected in its RFA guidance, is to 

provide as much information as 

possible, given time and resource 

constraints, to enable an informed Panel 

discussion. In this rulemaking, because 

of a court-ordered deadline, the EPA 

was unable to hold a pre-panel meeting 

but still provided SERs with the 

information available at the time, held 

a standard Panel Outreach meeting to 

collect verbal advice and 

recommendations from SERs, and 

provided the standard 14-day written 

comment period to SERs. The EPA 

received substantial input from the 

SERs, and the Panel report describes 

recommendations made by the Panel on 

measures the Administrator should 

consider that would minimize the 

economic impact of the proposed rule 

on small entities. The EPA complied 

with the RFA. In addition, we met with 

representatives of small businesses, 

small rural cooperatives, and small 

governments a number of times during 

the regulatory development process to 

discuss their issues and concerns 

regarding the proposed MATS rule for 

EGUs. 

Comment: One commenter requested 

that the EPA work with utilities such 

that new regulations are as flexible and 

cost efficient as possible. 

Response: In developing the final 

rule, the EPA has considered all 

information provided prior to, as well as 

in response to, the proposed rule. The 

EPA has endeavored to make the final 

regulations flexible and cost-efficient 

while adhering to the requirements of 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9435 

the CAA. The final rule includes a 

number of flexibilities, such as those 

related to monitoring requirements, that 

will lower costs and simplify 

compliance for small businesses and 

local governments. 

Comment: One commenter was 

concerned about the ability of small 

entities or nonprofit utilities such as 

those owned and/or operated by rural 

electric co-op utilities, and municipal 

utilities to comply with the proposed 

standards within 3 years. The 

commenter believes that the EPA 

disregarded the SER panelists who 

explained that under these current 

economic conditions they have 

constraints on their ability to raise 

capital for the construction of control 

projects and to acquire the necessary 

resources in order to meet a 3-year 

compliance deadline. Two commenters 

expressed concern that smaller utilities 

and those in rural areas will be unable 

to get vendors to respond to their 

requests for proposals, because they will 

be able to make more money serving 

larger utilities. 

Response: The preamble to the 

proposed rule (76 FR 25054; May 3, 

2011) provides a detailed discussion of 

how the EPA determined compliance 

times for the proposed (and final) rule. 

The EPA has provided pursuant to CAA 

section 112(i)(3)(A) the maximum 3-year 

period for sources to come into 

compliance. Sources may also seek a 1- 

year extension of the compliance period 

from their Title V permitting authority 

if the source needs that time to install 

controls. See CAA section 112(i)(3)(B). If 

the situation described by commenters 

(i.e., where small entities or nonprofit 

utilities constraints on ability to raise 

capital for construction of control 

projects and to acquire necessary 

resources) results in the source needing 

additional time to install controls, they 

would be in a position to request the 1- 

year extension. 

Comment: Several commenters 

believe the EPA did not adequately 

consider the disproportionately large 

impact on smaller generating units. The 

commenters note the diseconomies in 

scale for pollution controls for such 

units. One commenter noted the rule 

will create a more serious compliance 

hurdle for small communities that 

depend on coal-fired generation to meet 

their base load demand. The commenter 

notes that by not subcategorizing units, 

the EPA is dictating a fuel switch due 

to the disproportionately high cost on 

small communities. The other 

commenter believes the MACT and 

NSPS standards are unachievable by 

going too far without really considering 

the impacts on small municipal units, as 

public power is critical to communities, 

jobs, economic viability and electric 

reliability. A generating and 

transmissions electric cooperative 

which qualifies as a small entity 

believes the rule will ultimately result 

in increased electricity costs to its 

members and will negatively impact the 

economies of the primarily rural areas 

that they serve. Another commenter 

believes there is no legal or factual basis 

for creating subcategories or weaker 

standards for state, tribal, or municipal 

governments or small entities that are 

operating obsolete units, particularly 

given the current market situation and 

applicable equitable factors. The 

commenter suggests both the EPA’s and 

SBA’s analyses focus exclusively on the 

effects on entities causing HAP 

emissions and primarily on those 

operating obsolete EGUs, and fail to 

consider either impacts on downwind 

businesses and governments or the 

positive impacts on small entities and 

governments owning and operating 

competing, clean and modern EGUs. 

Response: The EPA disagrees with the 

commenters’ belief that the impacts on 

smaller generating units were not 

adequately considered when developing 

the rule. The EPA determined the 

number of potentially impacted small 

entities and assessed the potential 

impact of the proposed action on small 

entities, including municipal units. A 

similar assessment was conducted in 

support of the final action. Specifically, 

the EPA estimated the incremental net 

annualized compliance cost, which is a 

function of the change in capital and 

operating costs, fuel costs, and change 

in revenue. The projected compliance 

cost was considered relative to the 

projected revenue from generation. 

Thus, the EPA’s analysis accounts not 

only for the additional costs these 

entities face resulting from compliance, 

but also the impact of higher electricity 

prices. The EPA evaluated suggestions 

from SERs, including subcategorization 

recommendations. In the preamble to 

the proposed rule, the EPA explains 

that, normally, any basis for 

subcategorizing must be related to an 

effect on emissions, rather than some 

difference which does not affect 

emissions performance. The EPA does 

not see a distinction between emissions 

from smaller generating units versus 

larger units. The EPA acknowledges the 

comment that there is no legal or factual 

basis for creating subcategories or 

weaker standards for state, tribal, or 

municipal governments or small entities 

that are operating obsolete units. 

Comment: One commenter notes that 

the EPA recognizes LEEs in the rule 

such that they should receive less 

onerous monitoring requirements; 

however, the EPA does not recognize 

that small and LEEs also need and merit 

more flexible and achievable pollution 

control requirements. The commenter 

notes that the capital costs for emissions 

control at small utility units is 

disproportionately high due to 

inefficiencies in Hg removal, space 

constraints for control technology 

retrofits, and the fact that small units 

have fewer rate base customers across 

which to 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, nonenvironmental factors, and other 

limitations. 

Response: The EPA acknowledges 

that the rule contains reduced 

monitoring requirements for existing 

units that qualify as LEEs. Although the 

EPA does not believe that reduced 

pollution control requirements are 

warranted for LEEs, including small 

entity LEEs, we believe that flexible and 

achievable pollution control 

requirements are promoted through 

alternative standards, alternative 

compliance options, and emissions 

averaging as a means of demonstrating 

compliance with the standards for 

existing EGUs. 

Comment: One commenter believes 

that the EPA should develop more 

limited monitoring requirements for 

small EGUs. The commenter notes small 

entities do not possess the monetary 

resources, manpower, or technical 

expertise needed to operate cutting-edge 

monitoring techniques such as Hg 

CEMS and PM CEMS. The commenter 

notes the EPA could have identified 

monitoring alternatives to the SER panel 

for consideration. 

Response: The EPA provided 

monitoring alternatives to using PM 

CEMS, HCl CEMS, and Hg CEMS in its 

proposed standards and in this final 

rule. The continuous compliance 

alternatives are available to all affected 

sources, including small entities. As 

alternatives to the use of PM CEMS and 

HCl CEMS, sources are allowed to 


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conduct additional performance testing. 

Sorbent trap monitoring is allowed in 

lieu of Hg CEMS. 

Comment: Several commenters 

believe the EPA has not sufficiently 

complied with the requirements of the 

RFA or adequately considered the 

impact this rulemaking would have on 

small entities. One commenter believes 

the EPA has not engaged in meaningful 

outreach and consultation with small 

entities and therefore recommends that 

the EPA seek to revise the court-ordered 

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 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. A commenter believes the 

EPA did not fully consider the 

subcategorization of sources such as 

boilers designed to burn lignite coals 

versus other fossil fuels, especially in 

regard to non-mercury metal and acid 

gas emissions. The commenter 

references the SBAR Panel Report 

suggestion provided in the preamble of 

the proposed rule that the EPA consider 

developing an area source vs. major 

source distinction for the source 

category and the EPA’s response. 

Another commenter is concerned that 

the recommendations made by the SER 

participants were ignored and not 

discussed in the rulemaking. 

Specifically, the commenter notes the 

EPA did not discuss subcategorizing by 

age, type of plant, fuel, physical space 

constraints or useful anticipated life of 

the plant. Nor did the EPA establish 

GACT for smaller emitters to alleviate 

regulatory costs and operational 

difficulties. A commenter believes it is 

likely that different numerical or work 

practice standards are appropriate for 

area sources of HAP. 

Response: The EPA disagrees with 

one commenter’s assertion that the 

agency has not complied with the 

requirements of the RFA. The EPA 

complied with both the letter and spirit 

of the RFA, notwithstanding the 

constraints of the court-ordered 

deadline. For example, the EPA notified 

the Chief Counsel for Advocacy of the 

SBA of its intent to convene a Panel; 

compiled a list of SERs for the Panel to 

consult with; and convened the Panel. 

The Panel met with SERs to collect their 

advice and recommendations; reviewed 

the EPA materials; and drafted a report 

of Panel findings. The EPA further 

disagrees with the commenter’s 

assertion that the EPA’s IRFA does not 

sufficiently consider impacts on small 

entities. The EPA’s IRFA, which is 

included in chapter 10 of the RIA for the 

proposed rule, addresses the statutorily 

required elements of an IRFA, such as 

the economic impact of the proposed 

rule on small entities and the Panel’s 

findings. 

The EPA disagrees with the comment 

that recommendations made by the 

SERs were not considered or discussed 

in the proposed rulemaking such as 

recommendations regarding 

subcategorization and separate GACT 

standards for area sources. The 

preamble to the proposed standards 

includes a detailed discussion of how 

the EPA determined which 

subcategories and sources would be 

regulated (76 FR 25036–25037; May 3, 

2011). In that discussion, the EPA 

explains the rationale for its proposed 

subcategories based on five unit design 

types. In addition, the EPA 

acknowledges the subcategorization 

suggestions from the SERs and explains 

its reasons for not subcategorizing on 

those bases. The preamble to the 

proposed standards also includes a 

discussion of the SERs’ suggestion that 

area source EGUs be distinguished from 

major-source EGUs and the EPA’s 

reasons for not making that distinction 

(76 FR 25020–25021; May 3, 2011). 

The EPA also disagrees with the 

suggestion that the Agency pursue an 

extension of the timeline for final 

rulemaking such that the SBAR Panel 

can be reconvened and a new IRFA can 

be prepared and released for public 

comment prior to the final rulemaking. 

The EPA entered into a Consent Decree 

to resolve litigation alleging that the 

EPA failed to perform a nondiscretionary duty to promulgate CAA 

section 112(d) standards for EGUs. See 

American Nurses Ass’n v. EPA, 08–2198 

(D.D.C.). That Decree required the EPA 

to sign the final MATS rule by 

November 16, 2011, unless the agency 

sought to extend the deadline consistent 

with the requirements of the 

modification provision of the Consent 

Decree. The EPA and Plaintiffs 

stipulated to a 30-day extension 

consistent with the modification 

provisions of the Consent Decree and 

the rule must be signed no later than 

December 16, 2011. If plaintiffs in the 

American Nurses litigation objected to 

an additional extension request, which 

we believe would have been likely, the 

Agency would have had to file a motion 

with the Court seeking an extension of 

the deadline. Consistent with governing 

case law, the Agency would have been 

required to demonstrate in its motion 

for extension that it was impossible to 

finalize the rule by the deadline 

provided in the Consent Decree. See 

Sierra Club v. Jackson, Civil Action No. 

01–1537 (D.D.C.) (Opinion of the Court 

denying EPA’s motion to extend a 

consent decree deadline). The EPA 

negotiated a 30-day extension and was 

able to complete the rule by December 

16, 2011; accordingly, the Agency had 

no basis for seeking a further extension 

of time. 

A detailed description of the changes 

made to the rule since proposal, 

including those made as a result of 

feedback received during the public 

comment process can be found in 

sections VI (NESHAP) and X (NSPS) of 

this preamble. Changes explained in the 

identified sections include those related 

to applicability; subcategorization; work 

practices; periods of startup, shutdown, 

and malfunction; initial testing and 

compliance; continuous compliance; 

and notification, recordkeeping, and 

reporting. 

4. Description and Estimate of the 

Affected Small Entities 

For the purposes of assessing the 

impacts of MATS on small entities, a 

small entity is defined as: 


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(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; 

(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 generating 

capacity up to 25 MW, small entities 

that do not own at least one combustion 

unit with a capacity greater than 25 MW 

were removed from the dataset. For the 

affected units remaining, boiler and 

generator capacity, heat input, 

generation, and emissions data were 

aggregated by owner and then by parent 

company. Entities with more than 4 

billion kWh of annual electricity 

generation were removed from the list, 

as were municipal owned entities with 

a population greater than 50,000. For 

cooperatives, investor owned utilities, 

and subdivisions that generate less than 

4 billion kWh of electricity annually but 

which may be part of a large entity, 

additional research on power sales, 

operating revenues, and other business 

activities was performed to make a final 

determination regarding size. Finally, 

small entities for which the IPM does 

not project generation in 2015 in the 

base case were omitted from the 

analysis because they are not projected 

to be operating and, thus, are not 

projected to face the costs of compliance 

with the rule. After omitting entities for 

the reasons above, the EPA identified a 

total of 82 potentially affected small 

entities that are affiliated with 102 

EGUs. 

5. Compliance Cost Impacts 

The number of potentially affected 

small entities by ownership type and 

potential impacts of MATS are 

presented in Chapter 7 of the RIA and 

summarized here. The EPA estimated 

the annualized net compliance cost to 

small entities to be approximately $106 

million in 2015 (2007$). 

The EPA assessed the economic and 

financial impacts of the final rule using 

the ratio of compliance costs to the 

value of revenues from electricity 

generation, and our results focus on 

those entities for which this measure 

could be greater than 1 percent or 3 

percent. Of the 82 small entities 

identified, The EPA’s analysis shows 40 

entities may experience compliance 

costs greater than 1 percent of base 

generation revenues in 2015, and 35 

may experience compliance costs 

greater than 3 percent of base revenues. 

Also, all generating capacity at 3 small 

entities is projected to be uneconomic to 

maintain. In this analysis, the cost of 

withdrawing a unit as uneconomic is 

estimated as the base case profit that is 

forgone by not operating under the 

policy case. Because 35 of the 82 total 

units, or more than 40 percent, are 

estimated to incur compliance cost 

greater than 3 percent of base revenues, 

the EPA has concluded that it cannot 

certify that there will be no significant 

economic impact on a substantial 

number of small entities (SISNOSE) for 

this rule. Results for small entities 

discussed here do not account for the 

reality that electricity markets are 

regulated in parts of the country. 

Entities operating in regulated or costof-service markets should be able to 

recover all of their costs of compliance 

through rate adjustments. 

Note that the estimated costs for small 

entities are significantly lower than 

those estimated by the EPA for the 

MATS proposal (which were $379 

million). This is driven by a small group 

of units (less than 6 percent) which 

were projected to be uneconomic to 

operate under the proposal (and hence 

incurred lost profits due to lost 

electricity revenues), but are now 

projected to continue their operations 

under MATS. In addition, the EPA’s 

modeling indicates one unit that would 

have operated at a low capacity factor 

under the base case would find it 

economical to increase its generation 

significantly under MATS to meet 

electricity demand in its region. 

Excluding this unit, the total cost 

impacts across all entities would be 

roughly $175 million. Changes in 

compliance behavior for this small 

group of units, in particular the one unit 

which operates at a higher capacity 

factor, has a substantial impact on total 

costs as their increased generation 

revenues offsets a large portion of the 

compliance costs. 

The most significant components of 

incremental costs to these entities are 

changes in electricity revenues, 

followed by the increased capital and 

operating costs for retrofits. Capital and 

operating costs increase across all 

ownership types, but the direction of 

changes in electricity revenues varies 

among ownership types. All ownership 

types, with the exception of private 

entities, experience a net gain in 

electricity revenues under the MATS, 

unlike projections from the EPA’s 

modeling during the proposal, where 

only municipals benefitted from higher 

electricity revenues. The change in 

electricity revenue takes into account 

both the profit lost from units that do 

not operate under the policy case and 

the difference in revenue for operating 

units under the policy case. According 

to the EPA’s modeling, an estimated 274 

MW of capacity owned by small entities 

are considered uneconomic to operate 

under the policy case, resulting in a net 

loss of $13 million (in 2007$) in profits. 

On the other hand, many operating 

units actually increase their electricity 

revenue due to higher electricity prices 

under MATS. In addition, as mentioned 

above, the EPA’s modeling indicates one 

unit finds it economical to increase its 

capacity factor significantly under the 

policy case which results in 

significantly higher revenues offsetting 

the costs. 

6. Description of Steps To Minimize 

Impacts on Small Entities 

Consistent with the requirements of 

the RFA and SBREFA, the EPA has 

taken steps to minimize the significant 

economic impact on small entities. 

Because this rule does not affect units 

with a generating capacity of less than 

25 MW, small entities that do not own 

at least one generating unit with a 

capacity greater than 25 MW are not 

subject to the rule. According to the 

EPA’s analysis, among the coal- and oilfired 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 


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rule based on the statutory definition of 

potentially regulated units. 

For units affected by the proposed 

rule, the EPA considered a number of 

comments received, both during the 

Small Business Advocacy Review 

(SBAR) Panel and the public comment 

period. While none of the alternatives 

adopted is specifically applied to small 

entities, the EPA believes these 

modifications will make compliance 

less onerous for all regulated units, 

including those owned by small entities. 

a. Work practice standards. The EPA 

proposed numerical emission standards 

that would apply at all times, including 

during periods of startup and shutdown. 

After reviewing comments and other 

data regarding the nature of these 

periods of operation, the EPA is 

finalizing a work practice standard for 

periods of startup and shutdown. The 

EPA is also finalizing work practice 

standards for organic HAP from all 

subcategories of EGUs. Descriptions of 

the work practice requirements for 

startup and shutdown, as well as 

organic HAP and limited-use liquid oilfired EGUs, can be found in section 

VI.D–E. of the preamble. 

b. Continuous compliance and 

notification, record-keeping, and 

reporting. The final rule greatly 

simplifies the continuous compliance 

requirements and provides two basic 

approaches for most situations: use of 

continuous monitoring and periodic 

testing. The frequency of periodic 

testing has been decreased from 

monthly in the proposal to quarterly in 

the final rule. In addition to simplifying 

compliance, the EPA believes these 

changes considerably reduce the overall 

burden associated with recordkeeping 

and reporting. These changes to the 

final rule are described in more detail in 

Section VI.G–H of this preamble. 

c. Subcategorization. The Small Entity 

Representatives on the SBAR Panel 

were generally supportive of 

subcategorization and suggested a 

number of additional subcategories the 

EPA should consider when developing 

the final rule. Although it was not 

consistent with the statute to adopt the 

proposed subcategories, the EPA 

maintained the existing subcategories 

and split the ‘‘liquid oil-fired units’’ 

subcategory into three subcategories— 

continental, non-continental units, and 

limited-use units. 

d. MACT floor calculations. As 

recommended by the EPA SBAR Panel 

representative, the EPA established the 

MACT floors using all the available ICR 

data that was received to the maximum 

extent possible consistent with the CAA 

requirements. The Agency believes this 

approach reasonably ensures that the 

emission limits selected as the MACT 

floors adequately represent the level of 

emissions actually achieved by the 

average of the units in the top 12 

percent, considering operational 

variability of those units. 

e. Alternatives not adopted. The EPA 

did not adopt several of the suggestions 

posed either during the SBAR Panel or 

public comment period. The EPA did 

not propose a percent reduction 

standard as an alternative to the 

concentration-based MACT floor. The 

percent reduction format for Hg and 

other HAP emissions would not have 

addressed the EPA’s consideration of 

coal preparation practices that remove 

Hg and other HAP before firing. Also, to 

account for the coal preparation 

practices, sources would be required to 

track the HAP concentrations in coal 

from the mine to the stack, and not just 

before and after the control device(s), 

and such an approach would be difficult 

to implement and enforce. Furthermore, 

the EPA does not believe the percent 

reduction standard is in line with the 

Court’s interpretation of the CAA 

section 112 requirements. Even if we 

believed it was appropriate to establish 

a percent reduction standard, we do not 

have the data necessary to establish 

percent reduction standards for HAP, as 

explained further in the response to 

comments document. 

The EPA determined not to establish 

GACT standards for area sources for a 

number of reasons. The data show that 

similar HAP emissions and control 

technologies are found on both major 

and area sources greater than 25 MW, 

and some large units are synthetic area 

sources. In fact, because of the 

significant number of well-controlled 

EGUs of all sizes, we believe it would 

be difficult to make a distinction 

between MACT and GACT. Moreover, 

the EPA believes the standards for area 

source EGUs should reflect MACT, 

rather than GACT, because there is no 

essential difference between area source 

and major source EGUs with respect to 

emissions of HAP. 

The EPA determined not to exercise 

its discretionary authority to establish 

health-based emission standards for HCl 

and other HAP acid gases. Given the 

limitations of the currently available 

information (e.g., the HAP mix where 

EGUs are located, and the cumulative 

impacts of respiratory irritants from 

nearby sources), the environmental 

effects of HCl and the other acid gas 

HAP, and the significant co-benefits 

from reductions in criteria pollutants 

the EPA determined that setting a 

conventional MACT standard for HCl 

and the other acid gas HAP was the 

appropriate course of action. 

As required by SBREFA section 212, 

the EPA also is preparing a Small Entity 

Compliance Guide to help small entities 

comply with this rule. Small entities 

will be able to obtain a copy of the 

Small Entity Compliance guide at the 

following Web site: http://www.epa.gov/ 

airquality/powerplanttoxics/ 

actions.html. 

D. Unfunded Mandates Reform Act of 

1995 

Title II of the UMRA of 1995, Public 

Law 104–4, establishes requirements for 

federal agencies to assess the effects of 

their regulatory actions on state, local, 

and tribal governments and the private 

sector. Under UMRA section 202, we 

generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to state, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any 1 year. Before 

promulgating a rule for which a written 

statement is needed, UMRA section 205 

generally requires us to identify and 

consider a reasonable number of 

regulatory alternatives and adopt the 

least costly, most cost-effective or least 

burdensome alternative that achieves 

the objectives of the rule. The 

provisions of UMRA section 205 do not 

apply when they are inconsistent with 

applicable law. Moreover, UMRA 

section 205 allows us to adopt an 

alternative other than the least costly, 

most cost-effective or least burdensome 

alternative if the Administrator 

publishes with the final rule an 

explanation why that alternative was 

not adopted. Before we establish any 

regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, we must develop a small 

government agency plan under UMRA 

section 203. The plan must provide for 

notifying potentially affected small 

governments, enabling officials of 

affected small governments to have 

meaningful and timely input in the 

development of regulatory proposals 

with significant federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

We have determined that this rule 

contains a federal mandate that may 

result in expenditures of $100 million or 

more for state, local, and tribal 

governments, in the aggregate, or the 

private sector in any 1 year. 

Accordingly, we have prepared a 

written statement entitled ‘‘Unfunded 

Mandates Reform Act Analysis’’ under 


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377EIA Annual Energy Outlook 2010 annual total 

electricity prices from 1960 to 2010, Table 8–10. 

378EIA Annual Energy Outlook 2010 annual total 

electricity prices from 1960 t0 2010, Table 8–10. 

379 Ibid. 

380 Ibid., EIA AEO 2010, Table–10 for price levels; 

and Chapterr 3 of the RIA for electricity price 

differential. 

UMRA section 202 that is within the 

RIA and which is summarized below. 

1. Statutory Authority 

As discussed elsewhere in this 

preamble, the statutory authority for this 

rulemaking is CAA section 112. Title III 

of the CAA Amendments was enacted to 

reduce nationwide air toxic emissions. 

CAA section 112(b) lists the 188 

chemicals, compounds, or groups of 

chemicals deemed by Congress to be 

HAP. These toxic air pollutants are to be 

regulated by NESHAP. 

CAA section 112(d) directs us to 

develop NESHAP which require 

existing and new major sources to 

control emissions of HAP using MACTbased standards. This NESHAP applies 

to all coal- and oil-fired EGUs. 

In compliance with UMRA section 

205(a), we identified and considered a 

reasonable number of regulatory 

alternatives. Additional information on 

the costs and environmental impacts of 

these regulatory alternatives were 

presented in the RIA for the rulemaking. 

The regulatory alternative upon 

which this rule is based represents the 

MACT floor for all regulated pollutants 

for all but one EGU subcategory for all 

but one regulated pollutant for that 

subcategory. These MACT floor-based 

standards represent the least costly and 

least burdensome alternative. Beyondthe-floor emission limits for Hg are for 

existing coal-fired EGUs in the 

subcategory for low rank virgin coal 

EGUs. 

2. Social Costs and Benefits 

The RIA prepared for this rule 

including the Agency’s assessment of 

costs and benefits is in the docket. 

It is estimated that HAP would be 

reduced by thousands of tons in 2015, 

relative to the base case, including 

reductions in HCl, HF, metallic HAP 

(including Hg), and several other 

organic HAP from EGUs. Studies have 

determined a relationship between 

exposure to certain of these HAP and 

the onset of cancer; however, the 

Agency is unable to provide a 

monetized estimate of the HAP benefits 

at this time. In addition, significant 

reductions in PM2.5 and SO2 will occur, 

including approximately 53 thousand 

tons of PM2.5 and over 1 million tons of 

SO2. These reductions will occur by 

2016 and are expected to continue 

throughout the life of the affected 

sources. The major health effect 

associated with reducing PM2.5 and 

PM2.5 precursors (such as SO2) is a 

reduction in premature mortality. Other 

health effects associated with PM2.5

emission reductions include avoiding 

cases of chronic bronchitis, heart 

attacks, asthma attacks, and work-lost 

days (i.e., days when employees are 

unable to work). Although we are 

unable to monetize the benefits 

associated with the HAP emissions 

reductions other than for Hg or all 

benefits associated with Hg reductions, 

we are able to monetize the benefits 

associated with the PM2.5 and SO2

emissions reductions. For SO2 and 

PM2.5, we estimated the benefits 

associated with health effects of PM but 

were unable to quantify all categories of 

benefits (particularly those associated 

with ecosystem and visibility effects). 

Our estimates of the monetized benefits 

in 2016 associated with the 

implementation of the final rule range 

from $37 billion to $90 billion (2007 

dollars) when using a 3 percent 

discount rate or from $33 billion to $81 

billion (2007 dollars) when using a 7 

percent discount rate). Our estimate of 

costs is $9.6 billion (2007 dollars). For 

more detailed information on the 

benefits and costs estimated for this 

rulemaking, refer to the RIA in the 

docket. 

3. Future and Disproportionate Costs 

The UMRA requires that we estimate, 

where accurate estimation is reasonably 

feasible, future compliance costs 

imposed by this rule and any 

disproportionate budgetary effects. Our 

estimates of the future compliance costs 

of this rule are discussed previously in 

this preamble. 

The EPA assessed the economic and 

financial impacts of the rule on 

government-owned entities using the 

ratio of compliance costs to the value of 

revenues from electricity generation, 

and our results focus on those entities 

for which this measure could be greater 

than 1 percent or 3 percent of base 

revenues. The EPA projects that 42 

government entities will have 

compliance costs greater than 1 percent 

of base generation revenue in 2016, and 

32 may experience compliance costs 

greater than 3 percent of base revenues. 

Overall, 6 units owned by government 

entities are expected to retire. The most 

significant components of incremental 

costs to these entities are the increased 

capital and operating costs, followed by 

changes in electricity revenues. For 

more details on these results and the 

methodology behind their estimation, 

see the results included in chapter 7 of 

the RIA. 

4. Effects on the National Economy 

The UMRA requires that we estimate 

the effect of this rule on the national 

economy. To the extent feasible, we 

must estimate the effect on productivity, 

economic growth, full employment, 

creation of productive jobs, and 

international competitiveness of the 

U.S. goods and services, if we determine 

that accurate estimates are reasonably 

feasible and that such effect is relevant 

and material. 

The nationwide economic impact of 

this rule is presented in the RIA in the 

docket. This analysis provides estimates 

of the effect of this rule on some of the 

categories mentioned above. 

The results of the economic impact 

analysis are summarized previously in 

this preamble. The results show that, 

relative to baseline, there will be an 

average 3.1 percent increase in 

electricity price on average nationwide 

in 2016, with the range of increases 

from 1.3 percent to 6.3 percent in 

regions throughout the U.S., and a less 

than 1 percent increase in natural gas 

price nationwide in 2016. The roughly 

3 percent incremental price effect of this 

rule is small relative to the changes 

observed in the absolute levels of 

electricity prices over the last 50 years, 

which have ranged from as much as 23 

percent lower (in 1969) to as much as 

23 percent higher (in 1982) than prices 

observed in 2010.377 Power generation 

from coal-fired plants will fall by about 

2 percent nationwide in 2016. No region 

of the U.S. is expected to experience a 

double-digit increase in retail electricity 

prices in 2015 or in any year later than 

that, according to the Agency’s analysis, 

as a result of this rule. To put the 

electricity price effects in context, the 

roughly 3 percent incremental increase 

in aggregate end-user electricity prices 

projected to occur over the next 4 years 

is about the same as the 3 percent 

absolute average change in total enduser electricity prices observed on an 

annual basis.378 Furthermore, the 

roughly 3 percent incremental price 

effect of this rule is small relative to the 

changes observed in the absolute levels 

of electricity prices over the last 50 

years, which have ranged from as much 

as 23 percent lower (in 1969) to as much 

as 23 percent higher (in 1982) than 

prices observed in 2010.379 Even with 

this rule in effect, electricity prices are 

projected to be lower in 2015 and 2020 

than they were in 2010.380

5. Consultation With Government 

The UMRA requires that we describe 

the extent of the Agency’s prior 

consultation with affected state, local, 


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and tribal officials, summarize the 

officials’ comments or concerns, and 

summarize our response to those 

comments or concerns. In addition, 

UMRA section 203 requires that we 

develop a plan for informing and 

advising small governments that may be 

significantly or uniquely impacted by a 

regulatory action. Consistent with the 

intergovernmental consultation 

provisions of UMRA section 204, the 

EPA initiated consultations with 

governmental entities affected by this 

rule. The EPA invited the following 10 

national organizations representing state 

and local elected officials to a meeting 

held on October 27, 2010, in 

Washington, DC: (1) National Governors 

Association; (2) National Conference of 

State Legislatures, (3) Council of State 

Governments, (4) National League of 

Cities, (5) U.S. Conference of Mayors, (6) 

National Association of Counties, (7) 

International City/County Management 

Association, (8) National Association of 

Towns and Townships, (9) County 

Executives of America, and (10) 

Environmental Council of States. These 

10 organizations of elected state and 

local officials have been identified by 

the EPA as the ‘‘Big 10’’ organizations 

appropriate to contact for purpose of 

consultation with elected officials. The 

purposes of the consultation were to 

provide general background on the rule, 

answer questions, and solicit input from 

state/local governments. During the 

meeting, officials asked clarifying 

questions regarding CAA section 112 

requirements and central decision 

points presented by the EPA (e.g., use of 

surrogate pollutants to address HAP, 

subcategorization of source category, 

assessment of emissions variability). 

They also expressed uncertainty with 

regard to how utility boilers owned/ 

operated by state and local entities 

would be impacted, as well as with 

regard to the potential burden 

associated with implementing the rule 

on state and local entities (i.e., burden 

to re-permit affected EGUs or update 

existing permits). Officials requested, 

and the EPA provided, addresses 

associated with the 112 state and local 

governments estimated to be potentially 

impacted by the rule. The EPA has not 

received additional questions or 

requests from state or local officials. 

Consistent with UMRA section 205, 

the EPA has identified and considered 

a reasonable number of regulatory 

alternatives. Because the potential 

existed for a significant impact for 

substantial number of small entities, the 

EPA convened a SBAR Panel to obtain 

advice and recommendation of 

representatives of the small entities that 

potentially would be subject to the 

requirements of the rule. As part of that 

process, the EPA considered several 

options, which are discussed previously 

in this preamble. Those options 

included establishing emission limits, 

establishing work practice standards, 

establishing subcategories, and 

consideration of monitoring options. 

The regulatory alternative selected is a 

combination of the options considered 

and includes provisions regarding a 

number of the recommendations 

resulting from the SBAR Panel process 

as described below (see the Regulatory 

Flexibility Act discussion in this section 

of the preamble for more detail). 

E. Executive Order 13132, Federalism 

Under EO 13132, the EPA may not 

issue an action that has federalism 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by state and local 

governments, or the EPA consults with 

state and local officials early in the 

process of developing the final action. 

The EPA has concluded that this 

action may have federalism 

implications, because it may impose 

substantial direct compliance costs on 

state or local governments, and the 

federal government will not provide the 

funds necessary to pay those costs. 

Accordingly, the EPA provides the 

following federalism summary impact 

statement as required by section 6(b) of 

EO 13132. 

Based on estimates in the RIA, 

provided in the docket, the final rule 

may have federalism implications 

because the rule may impose 

approximately $294 million in annual 

direct compliance costs on an estimated 

96 state or local governments. 

Specifically, we estimate that there are 

80 municipalities, 5 states, and 11 

political subdivisions (i.e., a public 

district with territorial boundaries 

embracing an area wider than a single 

municipality and frequently covering 

more than one county for the purpose of 

generating, transmitting and distributing 

electric energy) that may be directly 

impacted by this final rule. Responses to 

the EPA’s 2010 ICR were used to 

estimate the nationwide number of 

potentially impacted state or local 

governments. As previously explained, 

this 2010 survey was submitted to all 

coal- and oil-fired EGUs listed in the 

2007 version of DOE/EIA’s ‘‘Annual 

Electric Generator Report,’’ and ‘‘Power 

Plant Operations Report.’’ 

The EPA consulted with state and 

local officials in the process of 

developing the rule to permit them to 

have meaningful and timely input into 

its development. The EPA met with 10 

national organizations representing state 

and local elected officials to provide 

general background on the rule, answer 

questions, and solicit input. In the final 

rule, EPA has provided flexibilities that 

will lower compliance costs for these 

entities. The EPA also recognizes that 

municipalities may need a longer 

compliance timeframe because of 

required approval processes. 

F. Executive Order 13175, Consultation 

and Coordination With Indian Tribal 

Governments 

Subject to EO 13175 (65 FR 67249; 

November 9, 2000) the EPA may not 

issue a regulation that has tribal 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by tribal governments, or 

the EPA consults with tribal officials 

early in the process of developing the 

proposed regulation and develops a 

tribal summary impact statement. 

Executive Order 13175 requires the EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

Tribal officials in the development of 

regulatory policies that have Tribal 

implications.’’ 

The EPA has concluded that this 

action may have tribal implications. The 

EPA offered consultation with tribal 

officials early in the regulation 

development process to permit them an 

opportunity to have meaningful and 

timely input. Consultation letters were 

sent to 584 tribal leaders and provided 

information regarding the EPA’s 

development of this rule and offered 

consultation. At the request of the 

tribes, three consultation meetings were 

held: December 7, 2010, with the Upper 

Sioux Community of Minnesota; 

December 13, 2010, with Moapa Band of 

Paiutes, Forest County Potawatomi, 

Standing Rock Sioux Tribal Council, 

and Fond du Lac Band of Chippewa; 

January 5, 2011, with the Forest County 

Potawatomi, and a representative from 

the National Tribal Air Association 

(NTAA). In these meetings, the EPA 

presented the authority under the CAA 

used to develop these rules and an 

overview of the industry and the 

industrial processes that have the 

potential for regulation. Tribes 

expressed concerns about the impact of 

EGUs in Indian country. Specifically, 

they were concerned about potential Hg 

deposition and the impact on the water 

resources of the tribes, with particular 

concern about the impact on subsistence 


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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 related to how the Agency would 

consider variability in setting the 

standards, and the use of tribal-specific 

fish consumption data from the tribes in 

our assessments. They were not 

supportive of using work practice 

standards as part of the rule, and asked 

the Agency to consider going beyond 

the MACT floor to offer more protection 

for the tribal communities. 

In addition to these consultations, the 

EPA also conducted outreach on this 

rule through presentations at the 

National Tribal Forum in Milwaukee, 

WI; phone calls with the NTAA; and a 

webinar for tribes on the proposed rule. 

The EPA specifically requested tribal 

data that could support the appropriate 

and necessary analyses and the RIA for 

this rule. In addition, the EPA held 

individual consultations with the 

Navajo Nation on October 12, 2011; as 

well as the Gila River Indian 

Community, Ak-Chin Indian 

Community, and the Hopi Nation on 

October 14, 2011. These tribes 

expressed concerns about the impact of 

the rule on the Navajo Generating 

Station (NGS), the impact on the cost of 

the water allotted to the tribes from the 

Central Arizona Project (CAP), the 

impact on tribal revenues from the coal 

mining operations (i.e., assumptions 

about reduced mining if NGS were to 

retire one or more units), and the 

impacts on employment of tribal 

members at both the NGS and the mine. 

More specific comments can be found in 

the docket. 

The EPA will continue to work with 

these and other potentially affected 

tribes as this final rule is implemented. 

G. Executive Order 13045, Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This final rule is subject to EO 13045 

(62 FR 19885; April 23, 1997) because 

it is an economically significant 

regulatory action as defined by EO 

12866, and EPA believes that the 

environmental health or safety risk 

addressed by this action may have a 

disproportionate effect on children. 

Accordingly, we have evaluated the 

environmental health or safety effects of 

the standards on children. 

Although this final rule is based on 

technology performance, the standards 

are designed to protect against hazards 

to public health with an adequate 

margin of safety as described in Section 

III of this preamble. The protection 

offered by this rule is particularly 

important for children, especially the 

developing fetus. As referenced in 

Chapter 4 of the RIA, ‘‘Mercury and 

Other HAP Benefits Analysis,’’ children 

are more vulnerable than adults to many 

HAP emitted by EGUs due to 

differential behavior patterns and 

physiology. These unique 

susceptibilities were carefully 

considered in a number of different 

ways in the analyses associated with 

this rulemaking, and are summarized in 

the RIA. We also estimate substantial 

health improvements for children in the 

form of 130,000 fewer asthma attacks, 

3,100 fewer emergency room visits due 

to asthma, 6,300 fewer cases of acute 

bronchitis, and approximately 140,000 

fewer cases of upper and lower 

respiratory illness. 

H. Executive Order 13211, Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

Executive Order 13211 (66 FR 28355; 

May 22, 2001) requires EPA to prepare 

and submit a Statement of Energy 

Effects to the Administrator of the Office 

of Information and Regulatory Affairs, 

OMB, for actions identified as 

‘‘significant energy actions.’’ This 

action, which is a significant regulatory 

action under EO 12866, is likely to have 

a significant adverse effect on the 

supply, distribution, or use of energy. 

We have prepared a Statement of Energy 

Effects for this action as follows. 

We estimate a 3.1 percent price 

increase for electricity nationwide in 

2016 and a less than 2 percent 

percentage fall in coal-fired power 

production as a result of this rule. The 

EPA projects that electric power sectordelivered natural gas prices will 

increase by about 0.6 percent over the 

2015 to 2030 timeframe. For more 

information on the estimated energy 

effects, please refer to the economic 

impact analysis for this final 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 (Pub. L. 104–113; 

15 U.S.C. 272 note) directs the EPA to 

use voluntary consensus standards in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. The NTTAA directs 

the EPA to provide Congress, through 

OMB, explanations when the Agency 

decides not to use available and 

applicable voluntary consensus 

standards. 

This rulemaking involves technical 

standards. The EPA cites the following 

standards in the final rule: EPA 

Methods 1, 2, 2A, 2C, 2F, 2G, 3A, 3B, 

4, 5, 5D, 17, 19, 23, 26, 26A, 29, 30B of 

40 CFR part 60 and Method 320 of 40 

CFR part 63. Consistent with the 

NTTAA, the EPA conducted searches to 

identify voluntary consensus standards 

in addition to these EPA methods. No 

applicable voluntary consensus 

standards were identified for EPA 

Methods 2F, 2G, 5D, and 19. The search 

and review results have been 

documented and are placed in the 

docket for the proposed rule. 

The three voluntary consensus 

standards described below were 

identified as acceptable alternatives to 

EPA test methods for the purposes of 

the final rule. 

The voluntary consensus standard 

American National Standards Institute 

(ANSI)/American Society of Mechanical 

Engineers (ASME) PTC 19–10–1981, 

‘‘Flue and Exhaust Gas Analyses [part 

10, Instruments and Apparatus]’’ is 

cited in the final rule for its manual 

method for measuring the O2, CO2, and 

CO content of exhaust gas. This part of 

ANSI/ASME PTC 19–10–1981 is an 

acceptable alternative to Method 3B. 

The voluntary consensus standard 

ASTM D6348–03 (Reapproved 2010), 

‘‘Standard Test Method for 

Determination of Gaseous Compounds 

by Extractive Direct Interface Fourier 

Transform (FTIR) Spectroscopy’’ is 

acceptable as an alternative to Method 

320 and is cited in the final rule, but 

with several conditions: (1) The test 

plan preparation and implementation in 

the Annexes to ASTM D6348–03, 

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 


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equation: Reported Result = (Measured 

Concentration in the Stack × 100)/% R. 

The voluntary consensus standard 

ASTM D6784–02, ‘‘Standard Test 

Method for Elemental, Oxidized, 

Particle-Bound and Total Mercury in 

Flue Gas Generated from Coal-Fired 

Stationary Sources (Ontario Hydro 

Method),’’ is an acceptable alternative to 

use of EPA Method 29 for Hg only or 

Method 30B for the purpose of 

conducting relative accuracy tests of Hg 

continuous monitoring systems under 

this final rule. Because of the limitations 

of this method in terms of total 

sampling volume, it is not appropriate 

for use in performance testing under 

this rule. In addition to the voluntary 

consensus standards the EPA used in 

the final rule, the search for emissions 

measurement procedures identified 16 

other voluntary consensus standards. 

The EPA determined that 14 of these 16 

standards identified for measuring 

emissions of the HAP or other 

pollutants subject to emission standards 

in the final rule were impractical 

alternatives to EPA test methods for the 

purposes of this final rule. Therefore, 

the EPA did not adopt these standards 

for this purpose. The reasons for this 

determination for the 14 methods are 

discussed below, and the remaining 2 

methods are discussed later in this 

section. 

The voluntary consensus standard 

ASTM D3154–00, ‘‘Standard Method for 

Average Velocity in a Duct (Pitot Tube 

Method),’’ is impractical as an 

alternative to EPA Methods 1, 2, 3B, and 

4 for the purposes of this rulemaking 

because the standard appears to lack in 

quality control and quality assurance 

requirements. Specifically, ASTM 

D3154–00 does not include the 

following: (1) proof that openings of 

standard pitot tube have not plugged 

during the test; (2) if differential 

pressure gauges other than inclined 

manometers (e.g., magnehelic gauges) 

are used, their calibration must be 

checked after each test series; and (3) 

the frequency and validity range for 

calibration of the temperature sensors. 

The voluntary consensus standard 

ASTM D3464–96 (Reapproved 2001), 

‘‘Standard Test Method Average 

Velocity in a Duct Using a Thermal 

Anemometer,’’ is impractical as an 

alternative to EPA Method 2 for the 

purposes of this rule primarily because 

applicability specifications are not 

clearly defined, e.g., range of gas 

composition, temperature limits. Also, 

the lack of supporting quality assurance 

data for the calibration procedures 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 Lshaped pitot, which historically has not 

been recommended by the EPA. The 

EPA specifies the S-type design which 

has large openings that are less likely to 

plug up with dust. 

The voluntary consensus standard, 

CAN/CSA Z223.2–M86 (1999), ‘‘Method 

for the Continuous Measurement of 

Oxygen, Carbon Dioxide, Carbon 

Monoxide, Sulphur Dioxide, and Oxides 

of Nitrogen in Enclosed Combustion 

Flue Gas Streams,’’ is unacceptable as a 

substitute for EPA Method 3A because 

it does not include quantitative 

specifications for measurement system 

performance, most notably the 

calibration procedures and instrument 

performance characteristics. The 

instrument performance characteristics 

that are provided are non-mandatory 

and also do not provide the same level 

of quality assurance as the EPA 

methods. For example, the zero and 

span/calibration drift is only checked 

weekly, whereas the EPA methods 

require drift checks after each run. 

Two very similar voluntary consensus 

standards, ASTM D5835–95 

(Reapproved 2001), ‘‘Standard Practice 

for Sampling Stationary Source 

Emissions for Automated Determination 

of Gas Concentration,’’ and ISO 

10396:1993, ‘‘Stationary Source 

Emissions: Sampling for the Automated 

Determination of Gas Concentrations,’’ 

are impractical alternatives to EPA 

Method 3A for the purposes of this final 

rule because they lack in detail and 

quality assurance/quality control 

requirements. Specifically, these two 

standards do not include the following: 

(1) Sensitivity of the method; (2) 

acceptable levels of analyzer calibration 

error; (3) acceptable levels of sampling 

system bias; (4) zero drift and 

calibration drift limits, time span, and 

required testing frequency; (5) a method 

to test the interference response of the 

analyzer; (6) procedures to determine 

the minimum sampling time per run 

and minimum measurement time; and 

(7) specifications for data recorders, in 

terms of resolution (all types) and 

recording intervals (digital and analog 

recorders, only). 

The voluntary consensus standard 

ISO 12039:2001, ‘‘Stationary Source 

Emissions—Determination of Carbon 

Monoxide, Carbon Dioxide, and 

Oxygen—Automated Methods,’’ is not 

acceptable as an alternative to EPA 

Method 3A. This ISO standard is similar 

to EPA Method 3A, but is missing some 

key features. In terms of sampling, the 

hardware required by ISO 12039:2001 

does not include a 3-way calibration 

valve assembly or equivalent to block 

the sample gas flow while calibration 

gases are introduced. In its calibration 

procedures, ISO 12039:2001 only 

specifies a two-point calibration while 

EPA Method 3A specifies a three-point 

calibration. Also, ISO 12039:2001 does 

not specify performance criteria for 

calibration error, calibration drift, or 

sampling system bias tests as in the EPA 

method, although checks of these 

quality control features are required by 

the ISO standard. 

The voluntary consensus standard 

ASTM D6522–00, ‘‘Standard Test 

Method for the Determination of 

Nitrogen Oxides, Carbon Monoxide, and 

Oxygen Concentrations in Emissions 

from Natural Gas-Fired Reciprocating 

Engines, Combustion Turbines, Boilers 

and Process Heaters Using Portable 

Analyzers’’ is not an acceptable 

alternative to EPA Method 3A for 

measuring CO and O2 concentrations for 

this final rule as the method is designed 

for application to sources firing natural 

gas. 

The voluntary consensus standard 

ASME PTC–38–80 R85 (1985), 

‘‘Determination of the Concentration of 

Particulate Matter in Gas Streams,’’ is 

not acceptable as an alternative for EPA 

Method 5 because ASTM PTC–38–80 is 

not specific about equipment 

requirements, and instead presents the 

options available and the pros and cons 

of each option. The key specific 

differences between ASME PTC–38–80 

and the EPA methods are that the ASME 

standard: (1) Allows in-stack filter 

placement as compared to the out-ofstack filter placement in EPA Methods 

5 and 17; (2) allows many different 

types of nozzles, pitots, and filtering 

equipment; (3) does not specify a filter 

weighing protocol or a minimum 

allowable filter weight fluctuation as in 

the EPA methods; and (4) allows filter 

paper to be only 99 percent efficient, as 

compared to the 99.95 percent 

efficiency required by the EPA methods. 

The voluntary consensus standard 

ASTM D3685/D3685M–98, ‘‘Test 

Methods for Sampling and 

Determination of Particulate Matter in 

Stack Gases,’’ is similar to EPA Methods 

5 and 17, but is lacking in the following 

areas that are needed to produce quality, 

representative particulate data: (1) 

Requirement that the filter holder 

temperature should be between 120°C 

and 134°C, and not just ‘‘above the acid 

dew-point’’; (2) detailed specifications 


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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. 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 

weighing every 6 hours until a constant 

weight is achieved. Third, EPA Method 

5 requires the filter weight to be 

reported to the nearest 0.1 milligram 

(mg), while CAN/CSA Z223.1 requires 

reporting only to the nearest 0.5 mg. 

Also, CAN/CSA Z223.1 allows the use 

of a standard pitot for velocity 

measurement when plugging of the tube 

opening is not expected to be a problem. 

The EPA Method 5 requires an S-shaped 

pitot. 

The voluntary consensus standard EN 

1911–1,2,3 (1998), ‘‘Stationary Source 

Emissions-Manual Method of 

Determination of HCl-Part 1: Sampling 

of Gases Ratified European Text-Part 2: 

Gaseous Compounds Absorption 

Ratified European Text-Part 3: 

Adsorption Solutions Analysis and 

Calculation Ratified European Text,’’ is 

impractical as an alternative to EPA 

Methods 26 and 26A. Part 3 of this 

standard cannot be considered 

equivalent to EPA Method 26 or 26A 

because the sample absorbing solution 

(water) would be expected to capture 

both HCl and chlorine gas, if present, 

without the ability to distinguish 

between the two. The EPA Methods 26 

and 26A use an acidified absorbing 

solution to first separate HCl and 

chlorine gas so that they can be 

selectively absorbed, analyzed, and 

reported separately. In addition, in EN 

1911 the absorption efficiency for 

chlorine gas would be expected to vary 

as the pH of the water changed during 

sampling. 

The voluntary consensus standard EN 

13211 (1998), is not acceptable as an 

alternative to the Hg portion of EPA 

Method 29 primarily because it is not 

validated for use with impingers, as in 

the EPA method, although the method 

describes procedures for the use of 

impingers. This European standard is 

validated for the use of fritted bubblers 

only and requires the use of a side 

(split) stream arrangement for isokinetic 

sampling because of the low sampling 

rate of the bubblers (up to 3 liters per 

minute, maximum). Also, only two 

bubblers (or impingers) are required by 

EN 13211, whereas EPA Method 29 

require the use of six impingers. In 

addition, EN 13211 does not include 

many of the quality control procedures 

of EPA Method 29, especially for the use 

and calibration of temperature sensors 

and controllers, sampling train assembly 

and disassembly, and filter weighing. 

Two of the 16 voluntary consensus 

standards identified in this search were 

not available at the time the review was 

conducted for the purposes of the final 

rule because they are under 

development by a voluntary consensus 

body: ASME/BSR MFC 13M, ‘‘Flow 

Measurement by Velocity Traverse,’’ for 

EPA Method 2 (and possibly 1); and 

ASME/BSR MFC 12M, ‘‘Flow in Closed 

Conduits Using Multiport Averaging 

Pitot Primary Flowmeters,’’ for EPA 

Method 2. 

Finally, in addition to the three 

voluntary consensus standards 

identified as acceptable alternatives to 

EPA methods required in the final rule, 

the EPA is also specifying four 

voluntary consensus standards in the 

rule for use in sampling and analysis of 

liquid oil samples for moisture content. 

These standards are: ASTM D95–05 

(Reapproved 2010), ‘‘Standard Test 

Method for Water in Petroleum Products 

and Bituminous Materials by 

Distillation,’’ ASTM D4006–11, 

‘‘Standard Test Method for Water in 

Crude Oil by Distillation,’’ ASTM 

D4177–95 (Reapproved 2010), 

‘‘Standard Practice for Automatic 

Sampling of Petroleum and Petroleum 

Products,’’ and ASTM D4057–06 

(Reapproved 2011), ‘‘Standard Practice 

for Manual Sampling of Petroleum and 

Petroleum Products.’’ 

Table 5, section 4.1.1.5 of appendix A, 

and section 3.1.2 of appendix B to 

subpart UUUUU, 40 CFR part 63, list 

the EPA testing methods included in the 

final rule. Under section 63.7(f) and 

section 63.8(f) of subpart A of the 

General Provisions, a source may apply 

to the EPA for permission to use 

alternative test methods or alternative 

monitoring requirements in place of any 

of the EPA testing methods, 

performance specifications, or 

procedures specified. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629; 

February 16, 1994) establishes federal 

executive policy on environmental 

justice (EJ). Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make EJ part of their mission by 

identifying and addressing, as 

appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the U.S. 

The EPA has determined that this 

final rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority, low income, and 

indigenous populations because it 

increases the level of environmental 

protection for all affected populations 

without having any disproportionately 


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381See Excess Local Deposition TSD for more 

detail. 

high and adverse human health or 

environmental effects on any 

population, including any minority, low 

income, and indigenous populations. 

This final rule establishes national 

emission standards for new and existing 

EGUs that combust coal and oil. The 

EPA estimates that there are 

approximately 1,400 units located at 

600 facilities covered by this final rule. 

This final rule will reduce emissions 

of all the listed HAP that come from 

EGUs. This includes metals (Hg, As, Be, 

Cd, Cr, Pb, Mn, Ni, and Se), organics 

(POM, acetaldehyde, acrolein, benzene, 

dioxins, ethylene dichloride, 

formaldehyde, and PCB), and acid gases 

(HCl and HF). At sufficient levels of 

exposure, these pollutants can cause a 

range of health effects including cancer; 

irritation of the lungs, skin, and mucous 

membranes; effects on the central 

nervous system such as memory and IQ 

loss and learning disabilities; damage to 

the kidneys; and other acute health 

disorders. 

The final rule will also result in 

substantial reductions of criteria 

pollutants such as CO, PM, and SO2. 

Sulfur dioxide is a precursor pollutant 

that is often transformed into fine PM 

(PM2.5) in the atmosphere. Reducing 

direct emissions of PM2.5 and SO2 will, 

as a result, reduce concentrations of 

PM2.5 in the atmosphere. These 

reductions in PM2.5 will provide large 

health benefits, such as reducing the 

risk of premature mortality for adults, 

chronic and acute bronchitis, childhood 

asthma attacks, and hospitalizations for 

other respiratory and cardiovascular 

diseases. (For more details on the health 

effects of metals, organics, and PM2.5, 

please refer to the RIA contained in the 

docket for this rulemaking.) This final 

rule will also have a small effect on 

electricity and natural gas prices but has 

the potential to affect the cost structure 

of the utility industry and could lead to 

shifts in how and where electricity is 

generated. 

This final rule is one of a group of 

regulatory actions that the EPA has 

taken and will take over the next several 

years to respond to statutory and 

judicial mandates that will reduce 

exposure to HAP and PM2.5, as well as 

to other pollutants, from EGUs and 

other sources. In addition, the EPA will 

pursue energy efficiency improvements 

throughout the economy, along with 

other federal agencies, states and other 

groups. This will contribute to 

additional environmental and public 

health improvements while lowering 

the costs of realizing those 

improvements. Together, these rules 

and actions will have substantial and 

long-term effects on both the U.S. power 

industry and on communities currently 

breathing dirty air. Therefore, we 

anticipate significant interest in many, if 

not most, of these actions from EJ 

communities, among many others. 

1. Key EJ Aspects of the Rule 

This is an air toxics rule; therefore, it 

does not permit emissions trading 

among sources. Instead, this final rule 

will place a limit on the rates of Hg and 

other HAP emitted from each affected 

EGU. As a result, emissions of Hg and 

other HAP such as HCl will be 

substantially reduced in the vast 

majority of states. In some states, 

however, there may be small increases 

in Hg and other HAP emissions due to 

shifts in electricity generation from 

EGUs with higher emission rates to 

EGUs with already low emission rates. 

Hydrogen chloride emissions are 

projected to increase at a small number 

of sources but that does not lead to any 

increased emissions at the state level. 

The primary risk analysis to support 

the finding that this final rule is both 

appropriate and necessary includes an 

analysis of the effects of Hg from EGUs 

on people who rely on freshwater fish 

they catch as a regular and frequent part 

of their diet. These groups are 

characterized as subsistence level 

fishing populations or fishers. A 

significant portion of the data in this 

analysis came from published studies of 

EJ communities where people 

frequently consume locally-caught 

freshwater fish. These communities 

included: (1) White and black 

populations (including female and poor 

strata) surveyed in South Carolina; (2) 

Hispanic, Vietnamese and Laotian 

populations surveyed in California; and 

(3) Great Lakes tribal populations 

(Chippewa and Ojibwe) active on ceded 

territories around the Great Lakes. These 

data were used to help estimate risks to 

similar populations beyond the areas 

where the study data were collected. For 

example, while the Vietnamese and 

Laotian survey data were collected in 

California, given the ethnic (heritage) 

nature of these high fish consumption 

rates, we assumed that they could also 

be associated with members of these 

ethnic groups living elsewhere in the 

U.S. Therefore, the high-end 

consumption rates referenced in the 

California study for these ethnic groups 

were used to model risk at watersheds 

elsewhere in the U.S. As a result of this 

approach, the specific fish consumption 

patterns of several different EJ groups 

are fundamental to the EPA’s 

assessment of both the underlying risks 

that make this final rule appropriate and 

necessary, and of the analysis of the 

benefits of reducing exposure to Hg and 

the other HAP. 

The EPA’s full analysis of risks from 

consumption of Hg-contaminated fish is 

contained in the RIA for this rule. The 

effects of this final rule on the health 

risks from Hg and other HAP are 

presented in the preamble and in the 

RIA for this rule. 

2. Potential Environmental and Public 

Health Impacts to Minority, Low 

Income, or Tribal Populations 

The EPA has conducted several 

analyses that provide additional insight 

on the potential effects of this rule on 

EJ communities. These include: (1) The 

socio-economic distribution of people 

living close to affected EGUs who may 

be exposed to pollution from these 

sources; and (2) an analysis of the 

distribution of health effects expected 

from the reductions in PM2.5 that will 

result from implementation of this final 

rule (co-benefits). 

a. Socio-Economic Distribution. As 

part of the analysis for this final rule, 

the EPA reviewed the aggregate 

demographic makeup of the 

communities near EGUs covered by this 

final rule. Although this analysis gives 

some indication of populations that may 

be exposed to levels of pollution that 

cause concern, it does not identify the 

demographic characteristics of the most 

highly affected individuals or 

communities. Electric generating units 

usually have very tall emission stacks; 

this tends to disperse the pollutants 

emitted from these stacks fairly far from 

the source. In addition, several of the 

pollutants emitted by these sources, 

such as a common form of Hg and SO2, 

are known to travel long distances and 

contribute to adverse impacts on both 

the environment and human health 

hundreds or even thousands of miles 

from where they were emitted (in the 

case of elemental Hg, globally). 

The proximity-to-the-source review is 

included in the analysis for this final 

rule because some EGUs emit enough 

HAP such as Ni or Cr(VI) to cause 

elevated lifetime cancer risks greater 

than 1 in a million in nearby 

communities. In addition, the EPA’s 

analysis indicates that there are 

localized areas with potential for 

elevated levels of Hg deposition around 

most U.S. EGUs.381

The analysis of demographic data 

used proximity-to-the-source 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 


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emissions from these sources. The 

demographic data for this analysis were 

extracted from the 2000 census data 

which were provided to the EPA by the 

U.S. Census Bureau. Distributions by 

race are based on demographic 

information at the census block level, 

and all other demographic groups are 

based on the extrapolation of census 

block group level data to the census 

block level. The socio-demographic 

parameters used in the analysis 

included the following categories: 

Racial (White, African American, Native 

American, Other or Multiracial, and All 

Other Races); Ethnicity (Hispanic); and 

Other (Number of people below the 

poverty line, Number of people with 

ages between 0 and 18, Number of 

people greater than or equal to 65, 

Number of people with no high school 

diploma). 

In determining the aggregate 

demographic makeup of the 

communities near affected sources, the 

EPA focused on those census blocks 

within three miles of affected sources 

and determined the demographic 

composition (e.g., race, income, etc.) of 

these census blocks and compared them 

to the corresponding compositions 

nationally. The radius of 3 miles (or 

approximately 5 kilometers) is 

consistent with other demographic 

analyses focused on areas around 

potential sources. In addition, air 

quality modeling experience has shown 

that the area within three miles of an 

individual source of emissions can 

generally be considered the area with 

the highest ambient air levels of the 

primary pollutants being emitted for 

most sources, both in absolute terms 

and relative to the contribution of other 

sources (assuming there are other 

sources in the area, as is typical in 

urban areas). Although facility processes 

and fugitive emissions may have more 

localized impacts, the EPA 

acknowledges that because of various 

stack heights there is the potential for 

dispersion beyond 3 miles. To the 

extent that any minority, low income, 

and indigenous subpopulation is 

disproportionately impacted by the 

current emissions as a result of the 

proximity of their homes to these 

sources, that subpopulation also stands 

to see increased environmental and 

health benefit from the emissions 

reductions called for by this rule. The 

results of the EPA’s demographic 

analysis for affected sources are shown 

in the following table: 382 383

TABLE 12—COMPARATIVE SUMMARY OF THE DEMOGRAPHICS WITHIN 5 KM (3 MILES) OF THE AFFECTED SOURCES

[Population in millions] 382

White African 

American 

Native 

American 

Other and multiracial Hispanic Minority 383 Below poverty 

line 

Near Source 

Total (3 mi) 8 .78 2 .51 0 .10 2 .52 2 .86 5 .13 2 .43 

% of Near 

Source Total 63 18 1 18 21 37 17 

National Total 215 35 2 .49 33 .3 39 .1 70 .8 37 .1 

% of National 

Total ............ 75 12 1 12 14 25 13 

382 Racial and ethnic categories overlap and cannot be summed. 383The ‘‘Minority’’ population is the overall population (in the first row) minus white population (in the second row). 

The data indicate that coal-fired EGUs 

are located in areas where the minority 

share of the population living within a 

three mile buffer is higher than the 

national average by 12 percentage points 

or 48 percent. For these same areas, the 

percent of the population below the 

poverty line is also higher than the 

national average by 4 percentage points 

or 31 percent. These results are 

presented in more detail in the ‘‘Review 

of Proximity Analysis,’’ February 2011, 

a copy of which is available in the 

docket. 

b. PM2.5 (Co-Benefits) Analysis. As 

mentioned above, many of the steps 

EGUs will take to reduce their emissions 

of air toxics as required by this final rule 

will also reduce emissions of PM and 

SO2. As a result, this final rule will 

reduce concentrations of PM2.5 in the 

atmosphere. Exposure to PM2.5 can 

cause or contribute to adverse health 

effects, such as asthma and heart 

disease, that significantly affect many 

minority, low-income, and tribal 

individuals and their communities. Fine 

PM (PM2.5) is particularly (but not 

exclusively) harmful to children, the 

elderly, and people with existing heart 

and lung diseases, including asthma. 

Exposure can cause premature death 

and trigger heart attacks, asthma attacks 

in children and adults with asthma, 

chronic and acute bronchitis, and 

emergency room visits and 

hospitalizations, as well as milder 

illnesses that keep children home from 

school and adults home from work. 

Missing work due to illness or the 

illness of a child is a particular problem 

for people who have jobs that do not 

provide paid sick days. Low-wage 

employees also risk losing their jobs if 

they are absent too often, even if it is 

due to their own illness or the illness of 

a child or other relative. Finally, many 

individuals in these communities lack 

access to high quality health care to 

treat these types of illnesses. Due to all 

these factors, many minority and lowincome communities are particularly 

susceptible to the health effects of PM2.5

and receive a variety of benefits from 

reducing it. 

We estimate that in 2016 the annual 

PM-related benefits of the final rule for 

adults include approximately 4,200 to 

11,000 fewer premature mortalities, 

2,900 fewer cases of chronic bronchitis, 

4,800 fewer non-fatal heart attacks, 

2,600 fewer hospitalizations (for 

respiratory and cardiovascular disease 

combined), 3.2 million fewer days of 

restricted activity due to respiratory 

illness and approximately 540,000 fewer 

lost work days. As described in EO 

13045, Protection of Children from 

Environmental Health Risks and Safety 

Risks, we also estimate substantial 

health improvements for children. 

We also examined the PM2.5 mortality 

risks according to race, income, and 

educational attainment. We then 

estimated the change in PM2.5 mortality 

risk as a result of this final rule among 

people living in the counties with the 

highest (top 5 percent) PM2.5 mortality 

risk in 2005. We then compared the 

change in risk among the people living 

in these ‘‘high-risk’’ counties with 

people living in all other counties. 

In 2005, people living in the highest 

risk counties and in the poorest counties 

had a substantially higher risk of PM2.5- 

related death than people living in the 

other 95 percent of counties. This was 


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true regardless of race; the difference 

between the groups of counties for each 

race was large while the differences 

among races in both groups of counties 

was very small. In contrast, the analysis 

found that people with less than high 

school education had a significantly 

greater risk from PM2.5 mortality than 

people with a greater than high school 

education. This was true both for the 

highest-risk counties and for the other 

counties. In summary, the analysis 

indicates that in 2005, educational 

status, living in one of the poorest 

counties, and living in a high-risk 

county are associated with higher PM2.5

mortality risk while race is not. 

Our analysis demonstrates that this 

final rule will significantly reduce the 

PM2.5 mortality among all populations 

of different races living throughout the 

U.S. compared to both 2005 and 2016 

pre-rule (i.e., base case) levels. The 

analysis indicates that people living in 

counties with the highest rates (top 5 

percent) of PM2.5 mortality risk in 2005 

receive the largest reduction in 

mortality risk after this rule takes effect. 

We also find that people living in the 

poorest 5 percent of the counties receive 

a larger reduction in PM2.5 mortality risk 

than all other counties. More 

information can be found in Section 

7.11 of the RIA. 

The EPA estimates that the benefits of 

the final rule are distributed among 

races, income levels, and levels of 

education fairly evenly. However, the 

analysis does indicate that this final rule 

in conjunction with the implementation 

of existing or final rules (e.g., the 

CSAPR) will reduce the disparity in risk 

between those in the highest-risk 

counties and the other 95 percent of 

counties for all races and educational 

levels. In addition, in many cases 

implementation of this final rule and 

other rules will, together, reduce risks in 

the highest-risk counties to the 

approximate level of risk for the rest of 

the counties as it existed before 

implementation of the rule. 

These results are presented in more 

detail in Section 7.11 of the RIA. 

3. Meaningful Public Participation 

The EPA defines ‘‘environmental 

justice’’ to include meaningful 

involvement of all people regardless of 

race, color, national origin, or income 

with respect to the development, 

implementation, and enforcement of 

environmental laws, regulations, and 

policies. To promote meaningful 

involvement, the EPA publicized the 

rulemaking via newsletters, EJ 

listserves, and the internet, including 

the Office of Policy’s (OP) Rulemaking 

Gateway Web site (http:// 

yosemite.epa.gov/opei/RuleGate.nsf/). 

During the comment period, the EPA 

discussed the proposed rule via a 

conference call with communities, 

conducted a community-oriented 

webinar on the proposed rule, and 

posted the webinar presentation online. The EPA also held three public 

hearings to receive additional input on 

the proposal. 

There will continue to be 

opportunities for public notice and 

comment as the utilities move forward 

with implementation of this rule. Once 

the rule is finalized, affected EGUs will 

need to update their Title V operating 

permits to reflect their new emission 

limits, any other new applicable 

requirements, and the associated 

monitoring and recordkeeping from this 

rule. The Title V permitting process 

provides that when most permits are 

reopened (for example, to incorporate 

new applicable requirements) or 

renewed, there must be opportunity for 

public review and comments. In 

addition, after the public review 

process, the EPA has an opportunity to 

review the proposed permit and object 

to its issuance if it does not meet CAA 

requirements. 

4. Additional Analysis 

In addition to the previously 

described assessment of EJ impacts, the 

EPA conducted an analysis of subpopulations with particularly high 

potential risks of Hg exposure due to 

high rates of fish consumption. These 

populations overlap in many cases with 

traditional EJ populations and would 

benefit from Hg reductions resulting 

from this rule. The EPA also conducted 

an analysis of the distribution of PM2.5- 

related mortality risk according to the 

race, income and education of the 

population and how MATS changes this 

distribution. These analyses can be 

found in Section 7.12 of the RIA. 

5. Summary 

This final rule strictly limits the 

emissions rate of Hg and other HAP 

from every affected EGU. The EPA’s 

analysis indicates substantial health 

benefits, including for minority, low 

income, and indigenous populations, 

from reductions in PM2.5. 

The EPA’s analysis also indicates 

reductions in risks for individuals, 

including for members of minority 

populations, who eat fish frequently 

from U.S. lakes and rivers and who live 

near affected sources. Based on all the 

available information, the EPA has 

determined that this final rule will not 

have disproportionately high and 

adverse human health or environmental 

effects on minority, low income, and 

indigenous populations. The EPA is 

providing multiple opportunities for EJ 

communities to both learn about and 

comment on this rule and welcomes 

their participation as implementation of 

the rule proceeds. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the U.S. The EPA will submit a report 

containing this rule and other required 

information to the U.S. Senate, the U.S. 

House of Representatives, and the 

Comptroller General of the U.S. prior to 

publication of the rule in the Federal 

Register. A major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is a ‘‘major 

rule’’ as defined by 5 U.S.C. 804(2). This 

rule will be effective April 16, 2012. 

List of Subjects 

40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

40 CFR Part 63 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances, Incorporation by reference, 

Intergovernmental relations, Reporting 

and recordkeeping requirements. 

Dated: December 16, 2011. 

Lisa P. Jackson, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, of the Code 

of the Federal Regulations is 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 paragraph (a)(93), 

added March 21, 2011, at 76 FR 15750, 

and delayed indefinitely at 76 FR 28664, 

May 18, 2011, as paragraph (a)(96); 


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■ b. By redesignating paragraphs (a)(91) 

and (a)(92) as paragraphs (a)(94) and 

(a)(95); 

■ c. By redesignating paragraphs (a)(89) 

and (a)(90) as paragraphs (a)(91) and 

(a)(92); 

■ d. By redesignating paragraphs (a)(54) 

through (a)(88) as paragraphs (a)(55) 

through (a)(89); 

■ e. By adding paragraph (a)(54); 

■ f. By adding paragraph (a)(90); and 

■ g. By adding paragraph (a)(93) to read 

as follows: 

§ 60.17 Incorporations by reference. 

* * * * * 

(a) * * * 

(54) ASTM D3699–08, Standard 

Specification for Kerosine, including 

Appendix X1, approved September 1, 

2008, IBR approved for §§ 60.41b of 

subpart Db of this part and 60.41c of 

subpart Dc of this part. 

* * * * * 

(90) ASTM D6751–11b, Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate Fuels, 

including Appendices X1 through X3, 

approved July 15, 2011, IBR approved 

for §§ 60.41b of subpart Db of this part 

and 60.41c of subpart Dc of this part. 

* * * * * 

(93) ASTM D7467–10, Standard 

Specification for Diesel Fuel Oil, 

Biodiesel Blend (B6 to B20), including 

Appendices X1 through X3, approved 

August 1, 2010, IBR approved for 

§§ 60.41b of subpart Db of this part and 

60.41c of subpart Dc of this part. 

* * * * * 

Subpart B—[Amended] 

■ 3. Section 60.21 is amended as 

follows: 

■ a. By revising paragraph (a). 

■ b. By revising paragraph (f). 

■ c. By removing paragraph (k). 

§ 60.21 Definitions. 

* * * * * 

(a) Designated pollutant means any 

air pollutant, the emissions of which are 

subject to a standard of performance for 

new stationary sources, but for which 

air quality criteria have not been issued 

and that is not included on a list 

published under section 108(a) or 

section 112(b)(1)(A) of the Act. 

* * * * * 

(f) Emission standard means a legally 

enforceable regulation setting forth an 

allowable rate of emissions into the 

atmosphere, establishing an allowance 

system, or prescribing equipment 

specifications for control of air pollution 

emissions. 

* * * * * 

■ 4. Section 60.24 is amended as 

follows: 

■ a. By revising paragraph (b)(1). 

■ b. By removing paragraph (h). 

§ 60.24 Emission standards and 

compliance schedules. 

* * * * * 

(b) * * * 

(1) Emission standards shall either be 

based on an allowance system or 

prescribe allowable rates of emissions 

except when it is clearly impracticable. 

Such cases will be identified in the 

guideline documents issued under 

§ 60.22. Where emission standards 

prescribing equipment specifications are 

established, the plan shall, to the degree 

possible, set forth the emission 

reductions achievable by 

implementation of such specifications, 

and may permit compliance by the use 

of equipment determined by the State to 

be equivalent to that prescribed. 

* * * * * 

Subpart D—[Amended] 

■ 5. The subpart heading for Subpart D 

is revised to read as follows: 

Subpart D—Standards of Performance 

for Fossil-Fuel-Fired Steam Generators 

■ 6. Section 60.40 is amended by 

revising paragraph (e) to read as follows: 

§ 60.40 Applicability and designation of 

affected facility. 

* * * * * 

(e) Any facility subject to either 

subpart Da or KKKK of this part is not 

subject to this subpart. 

■ 7. Section 60.41 is amended by adding 

the definition of ‘‘natural gas’’ in 

alphabetical order to read as follows: 

§ 60.41 Definitions. 

* * * * * 

Natural gas means a fluid mixture of 

hydrocarbons (e.g., methane, ethane, or 

propane), composed of at least 70 

percent methane by volume or that has 

a gross calorific value between 35 and 

41 megajoules (MJ) per dry standard 

cubic meter (950 and 1,100 Btu per dry 

standard cubic foot), that maintains a 

gaseous state under ISO conditions. In 

addition, natural gas contains 20.0 

grains or less of total sulfur per 100 

standard cubic feet. Finally, natural gas 

does not include the following gaseous 

fuels: landfill gas, digester gas, refinery 

gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven 

gas, or any gaseous fuel produced in a 

process which might result in highly 

variable sulfur content or heating value. 

* * * * * 

■ 8. Section 60.42 is amended as 

follows: 

■ a. By revising paragraph (a) 

introductory text. 

■ b. By adding paragraph (d). 

■ c. By adding paragraph (e). 

§ 60.42 Standard for particulate matter 

(PM). 

(a) Except as provided under 

paragraphs (b), (c), (d), and (e) of this 

section, on and after the date on which 

the performance test required to be 

conducted by § 60.8 is completed, no 

owner or operator subject to the 

provisions of this subpart shall cause to 

be discharged into the atmosphere from 

any affected facility any gases that: 

* * * * * 

(d) An owner or operator of an 

affected facility that combusts only 

natural gas is exempt from the PM and 

opacity standards specified in paragraph 

(a) of this section. 

(e) An owner or operator of an 

affected facility that combusts only 

gaseous or liquid fossil fuel (excluding 

residual oil) with potential SO2

emissions rates of 26 ng/J (0.060 lb/ 

MMBtu) or less and that does not use 

post-combustion technology to reduce 

emissions of SO2 or PM is exempt from 

the PM standards specified in paragraph 

(a) of this section. 

■ 9. Section 60.45 is amended as 

follows: 

■ a. By revising paragraph (a). 

■ b. By revising paragraph (b) 

introductory text. 

■ c. By revising paragraphs (b)(1) 

through (5). 

■ d. By revising paragraph (b)(6) 

introductory text. 

■ e. By revising paragraphs (b)(7)(i)(A) 

through (C). 

■ f. By revising paragraph (b)(7)(ii)(B). 

■ g. By adding paragraph (b)(8). 

§ 60.45 Emissions and fuel monitoring. 

(a) Each owner or operator of an 

affected facility subject to the applicable 

emissions standard shall install, 

calibrate, maintain, and operate 

continuous opacity monitoring system 

(COMS) for measuring opacity and a 

continuous emissions monitoring 

system (CEMS) for measuring SO2

emissions, NOX emissions, and either 

oxygen (O2) or carbon dioxide (CO2) 

except as provided in paragraph (b) of 

this section. 

(b) Certain of the CEMS and COMS 

requirements under paragraph (a) of this 

section do not apply to owners or 

operators under the following 

conditions: 

(1) For a fossil-fuel-fired steam 

generator that combusts only gaseous or 

liquid fossil fuel (excluding residual oil) 


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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 during the 

performance test that emissions of NOX

are less than 70 percent of the 

applicable standards in § 60.44, a CEMS 

for measuring NOX emissions is not 

required. If the initial performance test 

results show that NOX emissions are 

greater than 70 percent of the applicable 

standard, the owner or operator shall 

install a CEMS for NOX within one year 

after the date of the initial performance 

tests under § 60.8 and comply with all 

other applicable monitoring 

requirements under this part. 

(4) If an owner or operator is not 

required to and elects not to install any 

CEMS for either SO2 or NOX, a CEMS 

for measuring either O2 or CO2 is not 

required. 

(5) For affected facilities using a PM 

CEMS, a bag leak detection system to 

monitor the performance of a fabric 

filter (baghouse) according to the most 

current requirements in § 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 

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. 

* * * * * 

(7) * * * 

(i) * * * 

(A) If no visible emissions are 

observed, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 12 

calendar months from the date that the 

most recent performance test was 

conducted or within 45 days of the next 

day that fuel with an opacity standard 

is combusted, whichever is later; 

(B) If visible emissions are observed 

but the maximum 6-minute average 

opacity is less than or equal to 5 

percent, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 6 

calendar months from the date that the 

most recent performance test was 

conducted or within 45 days of the next 

day that fuel with an opacity standard 

is combusted, whichever is later; 

(C) If the maximum 6-minute average 

opacity is greater than 5 percent but less 

than or equal to 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 3 calendar months 

from the date that the most recent 

performance test was conducted or 

within 45 days of the next day that fuel 

with an opacity standard is combusted, 

whichever is later; or 

* * * * * 

(ii) * * * 

(B) If no visible emissions are 

observed for 10 operating days during 

which an opacity standard is applicable, 

observations can be reduced to once 

every 7 operating days during which an 

opacity standard is applicable. If any 

visible emissions are observed, daily 

observations shall be resumed. 

* * * * * 

(8) A COMS for measuring the opacity 

of emissions is not required for an 

affected facility at which the owner or 

operator installs, calibrates, operates, 

and maintains a particulate matter 

continuous parametric monitoring 

system (PM CPMS) according to the 

requirements specified in subpart 

UUUUU of part 63. 

* * * * * 

Subpart Da—[Amended] 

■ 10. The subpart heading for Subpart 

Da is revised to read as follows: 

Subpart Da—Standards of 

Performance for Electric Utility Steam 

Generating Units 

■ 11. Section 60.40Da is amended by 

revising paragraphs (b)(1) and (e) to read 

as follows: 

§ 60.40Da Applicability and designation of 

affected facility. 

* * * * * 

(b) * * * 

(1) The IGCC electric utility steam 

generating unit is capable of combusting 

more than 73 MW (250 MMBtu/h) heat 

input of fossil fuel (either alone or in 

combination with any other fuel) in the 

combustion turbine engine and 

associated heat recovery steam 

generator; and 

* * * * * 

(e) Applicability of this subpart to an 

electric utility combined cycle gas 

turbine other than an IGCC electric 

utility steam generating unit is as 

specified in paragraphs (e)(1) through 

(3) of this section. 

(1) Affected facilities (i.e. heat 

recovery steam generators used with 

duct burners) associated with a 

stationary combustion turbine that are 

capable of combusting more than 73 

MW (250 MMBtu/h) heat input of fossil 

fuel are subject to this subpart except in 

cases when the affected facility (i.e. heat 

recovery steam generator) meets the 

applicability requirements of and is 

subject to subpart KKKK of this part. 

(2) For heat recovery steam generators 

use with duct burners subject to this 

subpart, only emissions resulting from 

the combustion of fuels in the steam 

generating unit (i.e. duct burners) are 

subject to the standards under this 

subpart. (The emissions resulting from 

the combustion of fuels in the stationary 

combustion turbine engine are subject to 

subpart GG or KKKK, as applicable, of 

this part.) 

(3) Any affected facility that meets the 

applicability requirements and is 

subject to subpart Eb or subpart CCCC 

of this part is not subject to the emission 

standards under subpart Da. 

■ 12. Section 60.41Da is amended as 

follows: 

■ a. By revising the definitions of 

‘‘boiler operating day’’, ‘‘gaseous fuel’’, 

‘‘integrated gasification combined cycle 

electric utility steam generating unit’’, 

‘‘natural gas’’, ‘‘petroleum’’, ‘‘potential 

combustion concentration’’, and ‘‘steam 

generating unit’’. 

■ b. By adding the definitions of 

‘‘affirmative defense’’, ‘‘combined heat 

and power’’, ‘‘gross energy output’’, ‘‘net 

energy output’’, ‘‘out-of-control period’’, 

and ‘‘petroleum coke’’ in alphabetical 

order. 


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■ c. By removing the definitions of 

‘‘available purchase power’’, 

‘‘cogeneration’’, ‘‘dry flue gas 

desulfurization technology ‘‘, ‘‘electric 

utility company’’, ‘‘emergency 

condition’’, ‘‘emission rate period’’, 

‘‘gross output’’, ‘‘interconnected’’, ‘‘net 

system capacity’’, ‘‘principal company’’, 

‘‘responsible official’’, ‘‘spare flue gas 

desulfurization system module’’, 

‘‘spinning reserve’’, ‘‘system emergency 

reserves’’, and ‘‘system load’’. 

§ 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. 

* * * * * 

Boiler operating day for units 

constructed, reconstructed, or modified 

before February 29, 2005, means a 24- 

hour period during which fossil fuel is 

combusted in a steam-generating unit 

for the entire 24 hours. For units 

constructed, reconstructed, or modified 

after February 28, 2005, boiler operating 

day means a 24-hour period between 12 

midnight and the following midnight 

during which any fuel is combusted at 

any time in the steam-generating unit. It 

is not necessary for fuel to be combusted 

the entire 24-hour period. 

* * * * * 

Combined heat and power, also 

known as ‘‘cogeneration,’’ means a 

steam-generating unit that 

simultaneously produces both electric 

(and mechanical) and useful thermal 

energy from the same primary energy 

source. 

* * * * * 

Gaseous fuel means any fuel that is 

present as a gas at standard conditions 

and includes, but is not limited to, 

natural gas, refinery fuel gas, process 

gas, coke-oven gas, synthetic gas, and 

gasified coal. 

* * * * * 

Gross energy output means: 

(1) For facilities constructed, 

reconstructed, or modified before May 

4, 2011, the gross electrical or 

mechanical output from the affected 

facility plus 75 percent of the useful 

thermal output measured relative to ISO 

conditions that is not used to generate 

additional electrical or mechanical 

output or to enhance the performance of 

the unit (i.e., steam delivered to an 

industrial process); 

(2) For facilities constructed, 

reconstructed, or modified after May 3, 

2011, the gross electrical or mechanical 

output from the affected facility minus 

any electricity used to power the 

feedwater pumps and any associated gas 

compressors (air separation unit main 

compressor, oxygen compressor, and 

nitrogen compressor) plus 75 percent of 

the useful thermal output measured 

relative to ISO conditions that is not 

used to generate additional electrical or 

mechanical output or to enhance the 

performance of the unit (i.e., steam 

delivered to an industrial process); 

(3) For combined heat and power 

facilities constructed, reconstructed, or 

modified after May 3, 2011, the gross 

electrical or mechanical output from the 

affected facility divided by 0.95 minus 

any electricity used to power the 

feedwater pumps and any associated gas 

compressors (air separation unit main 

compressor, oxygen compressor, and 

nitrogen compressor) plus 75 percent of 

the useful thermal output measured 

relative to ISO conditions that is not 

used to generate additional electrical or 

mechanical output or to enhance the 

performance of the unit (i.e., steam 

delivered to an industrial process); 

(4) For a IGCC electric utility 

generating unit that coproduces 

chemicals constructed, reconstructed, or 

modified after May 3, 2011, the gross 

useful work performed is the gross 

electrical or mechanical output from the 

unit minus electricity used to power the 

feedwater pumps and any associated gas 

compressors (air separation unit main 

compressor, oxygen compressor, and 

nitrogen compressor) that are associated 

with power production plus 75 percent 

of the useful thermal output measured 

relative to ISO conditions that is not 

used to generate additional electrical or 

mechanical output or to enhance the 

performance of the unit (i.e., steam 

delivered to an industrial process). 

Auxiliary loads that are associated with 

power production are determined based 

on the energy in the coproduced 

chemicals compared to the energy of the 

syngas combusted in combustion 

turbine engine and associated duct 

burners. 

* * * * * 

Integrated gasification combined 

cycle electric utility steam 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 solidderived fuel not meeting the definition 

of natural gas. The Administrator may 

waive the 50 percent solid-derived fuel 

requirement during periods of the 

gasification system construction or 

repair. No solid fuel is directly burned 

in the unit during operation. 

* * * * * 

Natural gas means a fluid mixture of 

hydrocarbons (e.g., methane, ethane, or 

propane), composed of at least 70 

percent methane by volume or that has 

a gross calorific value between 35 and 

41 megajoules (MJ) per dry standard 

cubic meter (950 and 1,100 Btu per dry 

standard cubic foot), that maintains a 

gaseous state under ISO conditions. In 

addition, natural gas contains 20.0 

grains or less of total sulfur per 100 

standard cubic feet. Finally, natural gas 

does not include the following gaseous 

fuels: landfill gas, digester gas, refinery 

gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven 

gas, or any gaseous fuel produced in a 

process which might result in highly 

variable sulfur content or heating value. 

Net energy output means the gross 

energy output minus the parasitic load 

associated with power production. 

Parasitic load includes, but is not 

limited to, the power required to operate 

the equipment used for fuel delivery 

systems, air pollution control systems, 

wastewater treatment systems, ash 

handling and disposal systems, and 

other controls (i.e., pumps, fans, 

compressors, motors, instrumentation, 

and other ancillary equipment required 

to operate the affected facility). 

* * * * * 

Out-of-control period means any 

period beginning with the quadrant 

corresponding to the completion of a 

daily calibration error, linearity check, 

or quality assurance audit that indicates 

that the instrument is not measuring 

and recording within the applicable 

performance specifications and ending 

with the quadrant corresponding to the 

completion of an additional calibration 

error, linearity check, or quality 

assurance audit following corrective 

action that demonstrates that the 

instrument is measuring and recording 

within the applicable performance 

specifications. 

Petroleum for facilities constructed, 

reconstructed, or modified before May 

4, 2011, means crude oil or a fuel 

derived from crude oil, including, but 

not limited to, distillate oil, and residual 

oil. For units constructed, 

reconstructed, or modified after May 3, 

2011, petroleum means crude oil or a 

fuel derived from crude oil, including, 

but not limited to, distillate oil, residual 

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 


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coke is typically derived from oil 

refinery coker units or other cracking 

processes. 

Potential combustion concentration 

means the theoretical emissions 

(nanograms per joule (ng/J), lb/MMBtu 

heat input) that would result from 

combustion of a fuel in an uncleaned 

state without emission control systems. 

For sulfur dioxide (SO2) the potential 

combustion concentration is determined 

under § 60.50Da(c). 

* * * * * 

Steam generating unit for facilities 

constructed, reconstructed, or modified 

before May 4, 2011, means any furnace, 

boiler, or other device used for 

combusting fuel for the purpose of 

producing steam (including fossil-fuelfired 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-fuelfired steam generators associated with 

combined cycle gas turbines; nuclear 

steam generators are not included) plus 

any integrated combustion turbines and 

fuel cells. 

* * * * * 

■ 13. Section 60.42Da is revised to read 

as follows: 

§ 60.42Da Standards for particulate matter 

(PM). 

(a) Except as provided in paragraph (f) 

of this section, on and after the date on 

which the initial performance test is 

completed or required to be completed 

under § 60.8, whichever date comes 

first, an owner or operator of an affected 

facility shall not cause to be discharged 

into the atmosphere from any affected 

facility for which construction, 

reconstruction, or modification 

commenced before March 1, 2005, any 

gases that contain PM in excess of 13 

ng/J (0.030 lb/MMBtu) heat input. 

(b) Except as provided in paragraphs 

(b)(1) and (b)(2) of this section, on and 

after the date the initial PM performance 

test is completed or required to be 

completed under § 60.8, whichever date 

comes first, an owner or operator of an 

affected facility shall not cause to be 

discharged into the atmosphere any 

gases which exhibit greater than 20 

percent opacity (6-minute average), 

except for one 6-minute period per hour 

of not more than 27 percent opacity. 

(1) An owner or operator of an 

affected facility that elects to install, 

calibrate, maintain, and operate a 

continuous emissions monitoring 

system (CEMS) for measuring PM 

emissions according to the requirements 

of this subpart is exempt from the 

opacity standard specified in this 

paragraph (b) of this section. 

(2) An owner or operator of an 

affected facility that combusts only 

natural gas is exempt from the opacity 

standard specified in paragraph (b) of 

this section. 

(c) Except as provided in paragraphs 

(d) and (f) of this section, on and after 

the date on which the initial 

performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification after 

February 28, 2005, but before May 4, 

2011, shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain PM in 

excess of either: 

(1) 18 ng/J (0.14 lb/MWh) gross energy 

output; or 

(2) 6.4 ng/J (0.015 lb/MMBtu) heat 

input derived from the combustion of 

solid, liquid, or gaseous fuel. 

(d) As an alternative to meeting the 

requirements of paragraph (c) of this 

section, the owner or operator of an 

affected facility for which construction, 

reconstruction, or modification 

commenced after February 28, 2005, but 

before May 4, 2011, may elect to meet 

the requirements of this paragraph. On 

and after the date on which the initial 

performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility shall 

cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain PM in excess of: 

(1) 13 ng/J (0.030 lb/MMBtu) heat 

input derived from the combustion of 

solid, liquid, or gaseous fuel, and 

(2) For an affected facility that 

commenced construction or 

reconstruction, 0.1 percent of the 

combustion concentration determined 

according to the procedure in 

§ 60.48Da(o)(5) (99.9 percent reduction) 

when combusting solid, liquid, or 

gaseous fuel, or 

(3) For an affected facility that 

commenced modification, 0.2 percent of 

the combustion concentration 

determined according to the procedure 

in § 60.48Da(o)(5) (99.8 percent 

reduction) when combusting solid, 

liquid, or gaseous fuel. 

(e) Except as provided in paragraph (f) 

of this section, the owner or operator of 

an affected facility that commenced 

construction, reconstruction, or 

modification commenced after May 3, 

2011, shall meet the requirements 

specified in paragraphs (e)(1) and (2) of 

this section. 

(1) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator shall cause to be discharged 

into the atmosphere from that affected 

facility at all times except during 

periods of startup and shutdown, any 

gases that contain PM in excess of the 

applicable emissions limit specified in 

paragraphs (e)(1)(i) or (ii) of this section. 

(i) For an affected facility which 

commenced construction or 

reconstruction, any gases that contain 

PM in excess of either: 

(A) 11 ng/J (0.090 lb/MWh) gross 

energy output; or 

(B) 12 ng/J (0.097 lb/MWh) net energy 

output. 

(ii) For an affected facility which 

commenced modification, any gases that 

contain PM in excess of 13 ng/J (0.015 

lb/MMBtu) heat input. 

(2) During periods of startup and 

shutdown, the owner or operator shall 

meet the work practice standards 

specified in Table 3 to subpart UUUUU 

of part 63. 

(f) An owner or operator of an affected 

facility that meets the conditions in 

either paragraphs (f)(1) or (2) of this 

section is exempt from the PM 

emissions limits in this section. 

(1) The affected facility combusts only 

gaseous or liquid fuels (excluding 

residual oil) with potential SO2

emissions rates of 26 ng/J (0.060 lb/ 

MMBtu) or less, and that does not use 

a post-combustion technology to reduce 

emissions of SO2 or PM. 

(2) The affected facility is operated 

under a PM commercial demonstration 

permit issued by the Administrator 

according to the provisions of § 60.47Da. 

■ 14. Section 60.43Da is amended as 

follows: 

■ a. The section heading is revised. 

■ b. By revising paragraphs (a)(1) and 

(2). 

■ c. By adding paragraphs (a)(3) and (4). 

■ d. By removing and reserving 

paragraph (c). 

■ e. By revising paragraph (f). 

■ f. By revising paragraph (i). 

■ g. By revising paragraph (k). 

■ h. By adding paragraph (l). 

■ i. By adding paragraph (m). 

§ 60.43Da Standards for sulfur dioxide 

(SO2). 

(a) * * * 

(1) 520 ng/J (1.20 lb/MMBtu) heat 

input and 10 percent of the potential 

combustion concentration (90 percent 

reduction); 

(2) 30 percent of the potential 

combustion concentration (70 percent 


srobinson on DSK4SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9451 

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 facility for which 

construction, reconstruction, or 

modification commenced after February 

28, 2005, but before May 4, 2011, shall 

cause to be discharged into the 

atmosphere from that affected facility, 

any gases that contain SO2 in excess of 

the applicable emissions limit specified 

in paragraphs (i)(1) through (3) of this 

section. 

(1) For an affected facility which 

commenced construction, any gases that 

contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; or 

(ii) 5 percent of the potential 

combustion concentration (95 percent 

reduction). 

(2) For an affected facility which 

commenced reconstruction, any gases 

that contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input; or 

(iii) 5 percent of the potential 

combustion concentration (95 percent 

reduction). 

(3) For an affected facility which 

commenced modification, any gases that 

contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input; or 

(iii) 10 percent of the potential 

combustion concentration (90 percent 

reduction). 

* * * * * 

(k) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility located in 

a noncontinental area for which 

construction, reconstruction, or 

modification commenced after February 

28, 2005, but before May 4, 2011, shall 

cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain SO2 in excess of 

the applicable emissions limit specified 

in paragraphs (k)(1) and (2) of this 

section. 

(1) For an affected facility that burns 

solid or solid-derived fuel, the owner or 

operator shall not cause to be 

discharged into the atmosphere any 

gases that contain SO2 in excess of 520 

ng/J (1.2 lb/MMBtu) heat input. 

(2) For an affected facility that burns 

other than solid or solid-derived fuel, 

the owner or operator shall not cause to 

be discharged into the atmosphere any 

gases that contain SO2 in excess of 230 

ng/J (0.54 lb/MMBtu) heat input. 

(l) Except as provided in paragraphs 

(j) and (m) of this section, on and after 

the date on which the initial 

performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility for which 

construction, reconstruction, or 

modification commenced after May 3, 

2011, shall cause to be discharged into 

the atmosphere from that affected 

facility, any gases that contain SO2 in 

excess of the applicable emissions limit 

specified in paragraphs (l)(1) and (2) of 

this section. 

(1) For an affected facility which 

commenced construction or 

reconstruction, any gases that contain 

SO2 in excess of either: 

(i) 130 ng/J (1.0 lb/MWh) gross energy 

output; or 

(ii) 140 ng/J (1.2 lb/MWh) net energy 

output; or 

(iii) 3 percent of the potential 

combustion concentration (97 percent 

reduction). 

(2) For an affected facility which 

commenced modification, any gases that 

contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; or 

(ii) 10 percent of the potential 

combustion concentration (90 percent 

reduction). 

(m) On and after the date on which 

the initial performance test is completed 

or required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

located in a noncontinental area for 

which construction, reconstruction, or 

modification commenced after May 3, 

2011, shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain SO2 in 

excess of the applicable emissions limit 

specified in paragraphs (m)(1) and (2) of 

this section. 

(1) For an affected facility that burns 

solid or solid-derived fuel, the owner or 

operator shall not cause to be 

discharged into the atmosphere any 

gases that contain SO2 in excess of 520 

ng/J (1.2 lb/MMBtu) heat input. 

(2) For an affected facility that burns 

other than solid or solid-derived fuel, 

the owner or operator shall not cause to 

be discharged into the atmosphere any 

gases that contain SO2 in excess of 230 

ng/J (0.54 lb/MMBtu) heat input. 

■ 15. Section 60.44Da is revised to read 

as follows: 

§ 60.44Da Standards for nitrogen oxides 

(NOX). 

(a) Except as provided in paragraph 

(h) of this section, on and after the date 

on which the initial performance test is 

completed or required to be completed 

under § 60.8, whichever date comes 

first, no owner or operator subject to the 

provisions of this subpart shall cause to 

be discharged into the atmosphere from 

any affected facility for which 

construction, reconstruction, or 

modification commenced before July 10, 

1997 any gases that contain NOX

(expressed as NO2) in excess of the 

applicable emissions limit in paragraphs 

(a)(1) and (2) of this section. 

(1) The owner or operator shall not 

cause to be discharged into the 

atmosphere any gases that contain NOX

in excess of the emissions limit listed in 

the following table as applicable to the 

fuel type combusted and as determined 

on a 30-boiler operating day rolling 

average basis. 

Fuel type 

Emission limit for heat 

input 

ng/J lb/MMBtu 

Gaseous fuels: 

Coal-derived fuels ..................................................................................................................................................... 210 0.50 

All other fuels ............................................................................................................................................................ 86 0.20 

Liquid fuels: 


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9452 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

Fuel type 

Emission limit for heat 

input 

ng/J lb/MMBtu 

Coal-derived fuels ..................................................................................................................................................... 210 0.50 

Shale oil .................................................................................................................................................................... 210 0.50 

All other fuels ............................................................................................................................................................ 130 0.30 

Solid fuels: 

Coal-derived fuels ..................................................................................................................................................... 210 0.50 

Any fuel containing more than 25%, by weight, coal refuse ................................................................................... (1) (1) 

Any fuel containing more than 25%, by weight, lignite if the lignite is mined in North Dakota, South Dakota, or Montana, and is combusted in a slag tap furnace 2 ........................................................................................................... 340 0.80 

Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat input emission limit 2 ............ 260 0.60 

Subbituminous coal ......................................................................................................................................................... 210 0.50 

Bituminous coal ............................................................................................................................................................... 260 0.60 

Anthracite coal ................................................................................................................................................................. 260 0.60 

All other fuels ................................................................................................................................................................... 260 0.60 

1Exempt from NOX standards and NOX monitoring requirements. 2Any fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel. 

(2) When two or more fuels are 

combusted simultaneously in an 

affected facility, the applicable 

emissions limit (En) is determined by 

proration using the following formula: 

Where: 

En = Applicable NOX emissions limit when 

multiple fuels are combusted 

simultaneously (ng/J heat input); 

w = Percentage of total heat input derived 

from the combustion of fuels subject to 

the 86 ng/J heat input standard; 

x = Percentage of total heat input derived 

from the combustion of fuels subject to 

the 130 ng/J heat input standard; 

y = Percentage of total heat input derived 

from the combustion of fuels subject to 

the 210 ng/J heat input standard; 

z = Percentage of total heat input derived 

from the combustion of fuels subject to 

the 260 ng/J heat input standard; and 

v = Percentage of total heat input delivered 

from the combustion of fuels subject to 

the 340 ng/J heat input standard. 

(b) [Reserved] 

(c) [Reserved] 

(d) Except as provided in paragraph 

(h) of this section, on and after the date 

on which the initial performance test is 

completed or required to be completed 

under § 60.8, whichever date comes 

first, no owner or operator of an affected 

facility that commenced construction, 

reconstruction, or modification after 

July 9, 1997, but before March 1, 2005, 

shall cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain NOX (expressed 

as NO2) in excess of the applicable 

emissions limit specified in paragraphs 

(d)(1) and (2) of this section as 

determined on a 30-boiler operating day 

rolling average basis. 

(1) For an affected facility which 

commenced construction, any gases that 

contain NOX in excess of 200 ng/J (1.6 

lb/MWh) gross energy output. 

(2) For an affected facility which 

commenced reconstruction, any gases 

that contain NOX in excess of 65 ng/J 

(0.15 lb/MMBtu) heat input. 

(e) Except as provided in paragraphs 

(f) and (h) of this section, on and after 

the date on which the initial 

performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification after 

February 28, 2005 but before May 4, 

2011, shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain NOX

(expressed as NO2) in excess of the 

applicable emissions limit specified in 

paragraphs (e)(1) through (3) of this 

section as determined on a 30-boiler 

operating day rolling average basis. 

(1) For an affected facility which 

commenced construction, any gases that 

contain NOX in excess of 130 ng/J (1.0 

lb/MWh) gross energy output. 

(2) For an affected facility which 

commenced reconstruction, any gases 

that contain NOX in excess of either: 

(i) 130 ng/J (1.0 lb/MWh) gross energy 

output; or 

(ii) 47 ng/J (0.11 lb/MMBtu) heat 

input. 

(3) For an affected facility which 

commenced modification, any gases that 

contain NOX in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; or 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input. 

(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 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9453 

30-day compliance period, the owner or 

operator shall not cause to be 

discharged into the atmosphere any 

gases that contain NOX (expressed as 

NO2) in excess of the computed 

weighted-average emissions limit based 

on the proportion of gross energy output 

(in MWh) generated during the 

compliance period for each of emissions 

limits in paragraphs (f)(1) and (2) of this 

section. 

(g) Except as provided in paragraphs 

(h) of this section and § 60.45Da, on and 

after the date on which the initial 

performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification after 

May 3, 2011, shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain NOX (expressed as NO2) in 

excess of the applicable emissions limit 

specified in paragraphs (g)(1) through 

(3) of this section. 

(1) For an affected facility which 

commenced construction or 

reconstruction, any gases that contain 

NOX in excess of either: 

(i) 88 ng/J (0.70 lb/MWh) gross energy 

output; or 

(ii) 95 ng/J (0.76 lb/MWh) net energy 

output. 

(2) For an affected facility which 

commenced construction or 

reconstruction and that burns 75 

percent or more coal refuse (by heat 

input) on a 12-month rolling average 

basis, any gases that contain NOX in 

excess of either: 

(i) 110 ng/J (0.85 lb/MWh) gross 

energy output; or 

(ii) 120 ng/J (0.92 lb/MWh) net energy 

output. 

(3) For an affected facility which 

commenced modification, any gases that 

contain NOX in excess of 140 ng/J (1.1 

lb/MWh) gross energy output. 

(h) The NOX emissions limits under 

this section do not apply to an owner or 

operator of an affected facility which is 

operating under a commercial 

demonstration permit issued by the 

Administrator in accordance with the 

provisions of § 60.47Da. 

■ 16. Section 60.45Da is revised to read 

as follows: 

§ 60.45Da Alternative standards for 

combined nitrogen oxides (NOX) and 

carbon monoxide (CO). 

(a) The owner or operator of an 

affected facility that commenced 

construction, reconstruction, or 

modification after May 3, 2011 as 

alternate to meeting the applicable NOX

emissions limits specified in § 60.44Da 

may elect to meet the applicable 

standards for combined NOX and CO 

specified in paragraph (b) of this 

section. 

(b) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8 

no owner or operator of an affected 

facility that commenced construction, 

reconstruction, or modification after 

May 3, 2011, shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain NOX (expressed as NO2) plus 

CO in excess of the applicable emissions 

limit specified in paragraphs (b)(1) 

through (3) of this section as determined 

on a 30-boiler operating day rolling 

average basis. 

(1) For an affected facility which 

commenced construction or 

reconstruction, any gases that contain 

NOX plus CO in excess of either: 

(i) 140 ng/J (1.1 lb/MWh) gross energy 

output; or 

(ii) 150 ng/J (1.2 lb/MWh) net energy 

output. 

(2) For an affected facility which 

commenced construction or 

reconstruction and that burns 75 

percent or more coal refuse (by heat 

input) on a 12-month rolling average 

basis, any gases that contain NOX plus 

CO in excess of either: 

(i) 160 ng/J (1.3 lb/MWh) gross energy 

output; or 

(ii) 170 ng/J (1.4 lb/MWh) net energy 

output. 

(3) For an affected facility which 

commenced modification, any gases that 

contain NOX plus CO in excess of 190 

ng/J (1.5 lb/MWh) gross energy output. 

■ 17. Section 60.47Da is amended as 

follows: 

■ a. By revising paragraph (c). 

■ b. By adding paragraph (f). 

■ c. By adding paragraph (g). 

■ d. By adding paragraph (h). 

■ e. By adding paragraph (i). 

§ 60.47Da Commercial demonstration 

permit. 

* * * * * 

(c) An owner or operator of an 

affected facility that uses fluidized bed 

combustion (atmospheric or 

pressurized) and who is issued a 

commercial demonstration permit by 

the Administrator is not subject to the 

SO2 emission reduction requirements 

under § 60.43Da(a) but must, as a 

minimum, reduce SO2 emissions to 15 

percent of the potential combustion 

concentration (85 percent reduction) on 

a 30-day rolling average basis and to less 

than 520 ng/J (1.20 lb/MMBtu) heat 

input on a 30-day rolling average basis. 

* * * * * 

(f) An owner or operator of an affected 

facility that uses a pressurized fluidized 

bed or a multi-pollutant emissions 

controls system who is issued a 

commercial demonstration permit by 

the Administrator is not subject to the 

total PM emission reduction 

requirements under § 60.42Da but must, 

as a minimum, reduce PM emissions to 

less than 6.4 ng/J (0.015 lb/MMBtu) heat 

input. 

(g) An owner or operator of an 

affected facility that uses a pressurized 

fluidized bed or a multi-pollutant 

emissions controls system who is issued 

a commercial demonstration permit by 

the Administrator is not subject to the 

SO2 standards or emission reduction 

requirements under § 60.43Da but must, 

as a minimum, reduce SO2 emissions to 

5 percent of the potential combustion 

concentration (95 percent reduction) or 

to less than 180 ng/J (1.4 lb/MWh) gross 

energy output on a 30-boiler operating 

day rolling average basis. 

(h) An owner or operator of an 

affected facility that uses a pressurized 

fluidized bed or a multi-pollutant 

emissions control system or advanced 

combustion controls who is issued a 

commercial demonstration permit by 

the Administrator is not subject to the 

NOX standards or emission reduction 

requirements under § 60.44Da but must, 

as a minimum, reduce NOX emissions to 

less than 130 ng/J (1.0 lb/MWh) or the 

combined NOX plus CO emissions to 

less than 180 ng/J (1.4 lb/MWh) gross 

energy output on a 30-boiler operating 

day rolling average basis. 

(i) Commercial demonstration permits 

may not exceed the following equivalent 

MW electrical generation capacity for 

any one technology category listed in 

the following table. 

Technology Pollutant 

Equivalent 

electrical 

capacity 

(MW electrical output) 

Multi-pollutant Emission Control ........................................................................................................................................ SO2 .......... 1,000 


srobinson on DSK4SPTVN1PROD with RULES2
9454 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

Technology Pollutant 

Equivalent 

electrical 

capacity 

(MW electrical output) 

Multi-pollutant Emission Control ........................................................................................................................................ NOX ......... 1,000 

Multi-pollutant Emission Control ........................................................................................................................................ PM ........... 1,000 

Pressurized Fluidized Bed Combustion ............................................................................................................................ SO2 .......... 1,000 

Pressurized Fluidized Bed Combustion ............................................................................................................................ NOX ......... 1,000 

Pressurized Fluidized Bed Combustion ............................................................................................................................ PM ........... 1,000 

Advanced Combustion Controls ........................................................................................................................................ NOX ......... 1,000 

■ 18. Section 60.48Da is amended as 

follows: 

■ a. By revising paragraphs (a) through 

(g). 

■ b. By revising paragraph (i). 

■ c. By revising paragraph (k)(1)(i). 

■ d. By revising paragraph (k)(2)(i). 

■ e. By revising paragraph (k)(2)(iv). 

■ f. By removing and reserving 

paragraph (l). 

■ g. By revising paragraph (m). 

■ h. By revising paragraph (n). 

■ i. By revising paragraphs (p)(5), (7), 

and (8). 

■ j. By adding paragraph (r). 

■ k. By adding paragraph (s). 

§ 60.48Da Compliance provisions. 

(a) For affected facilities for which 

construction, modification, or 

reconstruction commenced before May 

4, 2011, the applicable PM emissions 

limit and opacity standard under 

§ 60.42Da, SO2 emissions limit under 

§ 60.43Da, and NOX emissions limit 

under § 60.44Da apply at all times 

except during periods of startup, 

shutdown, or malfunction. For affected 

facilities for which construction, 

modification, or reconstruction 

commenced after May 3, 2011, the 

applicable SO2 emissions limit under 

§ 60.43Da, NOX emissions limit under 

§ 60.44Da, and NOX plus CO emissions 

limit under § 60.45Da apply at all times. 

The applicable PM emissions limit and 

opacity standard under § 60.42Da apply 

at all times except during periods of 

startup and shutdown. 

(b) After the initial performance test 

required under § 60.8, compliance with 

the applicable SO2 emissions limit and 

percentage reduction requirements 

under § 60.43Da, NOX emissions limit 

under § 60.44Da, and NOX plus CO 

emissions limit under § 60.45Da is 

based on the average emission rate for 

30 successive boiler operating days. A 

separate performance test is completed 

at the end of each boiler operating day 

after the initial performance test, and a 

new 30-boiler operating day rolling 

average emission rate for both SO2, NOX

or NOX plus CO as applicable, and a 

new percent reduction for SO2 are 

calculated to demonstrate compliance 

with the standards. 

(c) For the initial performance test 

required under § 60.8, compliance with 

the applicable SO2 emissions limits and 

percentage reduction requirements 

under § 60.43Da, the NOX emissions 

limits under § 60.44Da, and the NOX

plus CO emissions limits under 

§ 60.45Da is based on the average 

emission rates for SO2, NOX, CO, and 

percent reduction for SO2 for the first 30 

successive boiler operating days. The 

initial performance test is the only test 

in which at least 30 days prior notice is 

required unless otherwise specified by 

the Administrator. The initial 

performance test is to be scheduled so 

that the first boiler operating day of the 

30 successive boiler operating days is 

completed within 60 days after 

achieving the maximum production rate 

at which the affected facility will be 

operated, but not later than 180 days 

after initial startup of the facility. 

(d) For affected facilities for which 

construction, modification, or 

reconstruction commenced before May 

4, 2011, compliance with applicable 30- 

boiler operating day rolling average SO2

and NOX emissions limits is determined 

by calculating the arithmetic average of 

all hourly emission rates for SO2 and 

NOX for the 30 successive boiler 

operating days, except for data obtained 

during startup, shutdown, or 

malfunction. For affected facilities for 

which construction, modification, or 

reconstruction commenced after May 3, 

2011, compliance with applicable 30- 

boiler operating day rolling average SO2

and NOX emissions limits is determined 

by dividing the sum of the SO2 and NOX

emissions for the 30 successive boiler 

operating days by the sum of the gross 

energy output or net energy output, as 

applicable, for the 30 successive boiler 

operating days. 

(e) For affected facilities for which 

construction, modification, or 

reconstruction commenced before May 

4, 2011, compliance with applicable 

SO2 percentage reduction requirements 

is determined based on the average inlet 

and outlet SO2 emission rates for the 30 

successive boiler operating days. For 

affected facilities for which 

construction, modification, or 

reconstruction commenced after May 3, 

2011, compliance with applicable SO2

percentage reduction requirements is 

determined based on the ‘‘as fired’’ total 

potential emissions and the total outlet 

SO2 emissions for the 30 successive 

boiler operating days. 

(f) For affected facilities for which 

construction, modification, or 

reconstruction commenced before May 

4, 2011, compliance with applicable 

daily average PM emissions limits is 

determined by calculating the 

arithmetic average of all hourly 

emission rates for PM each boiler 

operating day, except for data obtained 

during startup, shutdown, and 

malfunction. Daily averages are only 

calculated for boiler operating days that 

have non-out-of-control data for at least 

18 hours of unit operation during which 

the standard applies. Instead, all of the 

non-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-ofcontrol hourly emission rates of the next 

boiler operating day with 18 hours or 

more of non-out-of-control PM CEMS 

data to determine compliance. For 

affected facilities for which 

construction, modification, or 

reconstruction commenced after May 3, 

2011, compliance with applicable daily 

average PM emissions limits is 

determined by dividing the sum of the 

PM emissions for the 30 successive 

boiler operating days by the sum of the 

gross useful output or net energy output, 

as applicable, for the 30 successive 

boiler operating days. 

(g) For affected facilities for which 

construction, modification, or 

reconstruction commenced after May 3, 

2011, compliance with applicable 30- 

boiler operating day rolling average NOX

plus CO emissions limit is determined 

by dividing the sum of the NOX plus CO 

emissions for the 30 successive boiler 

operating days by the sum of the gross 

energy output or net energy output, as 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9455 

applicable, for the 30 successive boiler 

operating days. 

* * * * * 

(i) Compliance provisions for sources 

subject to § 60.44Da(d)(1), (e)(1), 

(e)(2)(i), (e)(3)(i), (f), or (g). The owner or 

operator shall calculate NOX emissions 

as 1.194 × 10¥7 lb/scf-ppm times the 

average hourly NOX output 

concentration in ppm (measured 

according to the provisions of 

§ 60.49Da(c)), times the average hourly 

flow rate (measured in scfh, according 

to the provisions of § 60.49Da(l) or 

§ 60.49Da(m)), divided by the average 

hourly gross energy output (measured 

according to the provisions of 

§ 60.49Da(k)) or the average hourly net 

energy output, as applicable. 

Alternatively, for oil-fired and gas-fired 

units, NOX emissions may be calculated 

by multiplying the hourly NOX emission 

rate in lb/MMBtu (measured by the 

CEMS required under § 60.49Da(c) and 

(d)), by the hourly heat input rate 

(measured according to the provisions 

of § 60.49Da(n)), and dividing the result 

by the average gross energy output 

(measured according to the provisions 

of § 60.49Da(k)) or the average hourly 

net energy output, as applicable. 

(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 energy 

output; 

Csg = Average hourly concentration of NOX

exiting the steam generating unit, ng/ 

dscm (lb/dscf); 

Cte = Average hourly concentration of NOX in 

the turbine exhaust upstream from duct 

burner, ng/dscm (lb/dscf); 

Qsg = Average hourly volumetric flow rate of 

exhaust gas from steam generating unit, 

dscm/h (dscf/h); 

Qte = Average hourly volumetric flow rate of 

exhaust gas from combustion turbine, 

dscm/h (dscf/h); 

Osg = Average hourly gross energy output 

from steam generating unit, J/h (MW); 

and 

h = Average hourly fraction of the total heat 

input to the steam generating unit 

derived from the combustion of fuel in 

the affected duct burner. 

* * * * * 

(2) * * * 

(i) The emission rate (E) of NOX shall 

be computed using Equation 3 in this 

section: 

Where: 

E = Emission rate of NOX from the duct 

burner, ng/J (lb/MWh) gross energy 

output; 

Csg = Average hourly concentration of NOX

exiting the steam generating unit, ng/ 

dscm (lb/dscf); 

Qsg = Average hourly volumetric flow rate of 

exhaust gas from steam generating unit, 

dscm/h (dscf/h); and 

Occ = Average hourly gross energy output 

from entire combined cycle unit, J/h 

(MW). 

* * * * * 

(iv) The owner or operator may, in 

lieu of installing, operating, and 

recording data from the continuous flow 

monitoring system specified in 

§ 60.49Da(l), determine the mass rate 

(lb/h) of NOX emissions by installing, 

operating, and maintaining continuous 

fuel flowmeters following the 

appropriate measurements procedures 

specified in appendix D of part 75 of 

this chapter. If this compliance option is 

selected, the emission rate (E) of NOX

shall be computed using Equation 4 in 

this section: 

Where: 

E = Emission rate of NOX from the duct 

burner, ng/J (lb/MWh) gross energy 

output; 

ERsg = Average hourly emission rate of NOX

exiting the steam generating unit heat 

input calculated using appropriate F 

factor as described in Method 19 of 

appendix A of this part, ng/J (lb/ 

MMBtu); 

Hcc = Average hourly heat input rate of entire 

combined cycle unit, J/h (MMBtu/h); and 

Occ = Average hourly gross energy output 

from entire combined cycle unit, J/h 

(MW). 

* * * * * 

(m) Compliance provisions for 

sources subject to § 60.43Da(i)(1)(i), 

(i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), (j)(3)(i), 

(l)(1)(i), (l)(1)(ii), or (l)(2). The owner or 

operator shall calculate SO2 emissions 

as 1.660 × 10¥7 lb/scf-ppm times the 

average hourly SO2 output 

concentration in ppm (measured 

according to the provisions of 

§ 60.49Da(b)), times the average hourly 

flow rate (measured according to the 

provisions of § 60.49Da(l) or 

§ 60.49Da(m)), divided by the average 

hourly gross energy output (measured 

according to the provisions of 

§ 60.49Da(k)) or the average hourly net 

energy output, as applicable. 

Alternatively, for oil-fired and gas-fired 

units, SO2 emissions may be calculated 

by multiplying the hourly SO2 emission 

rate (in lb/MMBtu), measured by the 

CEMS required under § 60.49Da, by the 

hourly heat input rate (measured 

according to the provisions of 

§ 60.49Da(n)), and dividing the result by 

the average gross energy output 

(measured according to the provisions 

of § 60.49Da(k)) or the average hourly 

net energy output, as applicable. 

(n) Compliance provisions for sources 

subject to § 60.42Da(c)(1) or (e)(1)(i). 

The owner or operator shall calculate 

PM emissions by multiplying the 

average hourly PM output concentration 

(measured according to the provisions 

of § 60.49Da(t)), by the average hourly 

flow rate (measured according to the 

provisions of § 60.49Da(l) or 

§ 60.49Da(m)), and dividing by the 

average hourly gross energy output 

(measured according to the provisions 


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9456 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

of § 60.49Da(k)) or the average hourly 

net energy output, as applicable. 

* * * * * 

(p) * * * 

(5) At a minimum, non-out-of-control 

CEMS hourly averages shall be obtained 

for 75 percent of all operating hours on 

a 30-boiler operating day rolling average 

basis. Beginning on January 1, 2012, 

non-out-of-control CEMS hourly 

averages shall be obtained for 90 percent 

of all operating hours on a 30-boiler 

operating day rolling average basis. 

(i) At least two data points per hour 

shall be used to calculate each 1-hour 

arithmetic average. 

(ii) [Reserved] 

* * * * * 

(7) All non-out-of-control CEMS data 

shall be used in calculating average 

emission concentrations even if the 

minimum CEMS data requirements of 

paragraph (j)(5) of this section are not 

met. 

(8) When PM emissions data are not 

obtained because of CEMS breakdowns, 

repairs, calibration checks, and zero and 

span adjustments, emissions data shall 

be obtained by using other monitoring 

systems as approved by the 

Administrator or EPA Reference Method 

19 of appendix A of this part to provide, 

as necessary, non-out-of-control 

emissions data for a minimum of 90 

percent (only 75 percent is required 

prior to January 1, 2012) of all operating 

hours per 30-boiler operating day rolling 

average. 

* * * * * 

(r) Compliance provisions for sources 

subject to § 60.45Da. To determine 

compliance with the NOX plus CO 

emissions limit, the owner or operator 

shall use the procedures specified in 

paragraphs (r)(1) through (3) of this 

section. 

(1) Calculate NOX emissions as 1.194 

× 10¥7 lb/scf-ppm times the average 

hourly NOX output concentration in 

ppm (measured according to the 

provisions of § 60.49Da(c)), times the 

average hourly flow rate (measured in 

scfh, according to the provisions of 

§ 60.49Da(l) or § 60.49Da(m)), divided 

by the average hourly gross energy 

output (measured according to the 

provisions of § 60.49Da(k)) or the 

average hourly net energy output, as 

applicable. 

(2) Calculate CO emissions by 

multiplying the average hourly CO 

output concentration (measured 

according to the provisions of 

§ 60.49Da(u), by the average hourly flow 

rate (measured according to the 

provisions of § 60.49Da(l) or 

§ 60.49Da(m)), and dividing by the 

average hourly gross energy output 

(measured according to the provisions 

of § 60.49Da(k)) or the average hourly 

net energy output, as applicable. 

(3) Calculate NOX plus CO emissions 

by summing the NOX emissions results 

from paragraph (r)(1) of this section plus 

the CO emissions results from paragraph 

(r)(2) of this section. 

(s) Affirmative defense for exceedance 

of emissions limit during malfunction. 

In response to an action to enforce the 

standards set forth in paragraph 

§§ 60.42Da, 60.43Da, 60.44Da, and 

60.45Da, you may assert an affirmative 

defense to a claim for civil penalties for 

exceedances of such standards that are 

caused by malfunction, as defined at 40 

CFR 60.2. Appropriate penalties may be 

assessed, however, if you fail to meet 

your burden of proving all of the 

requirements in the affirmative defense 

as specified in paragraphs (s)(1) and (2) 

of this section. The affirmative defense 

shall not be available for claims for 

injunctive relief. 

(1) To establish the affirmative 

defense in any action to enforce such a 

limit, you must timely meet the 

notification requirements in paragraph 

(s)(2) of this section, and must prove by 

a preponderance of evidence that: 

(i) The excess emissions: 

(A) Were caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control and monitoring 

equipment, process equipment, or a 

process to operate in a normal or usual 

manner; and 

(B) Could not have been prevented 

through careful planning, proper design, 

or better operation and maintenance 

practices; and 

(C) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(D) Were not part of a recurring 

pattern indicative of inadequate design, 

operation, or maintenance; and 

(ii) Repairs were made as 

expeditiously as possible when the 

applicable emissions limits were being 

exceeded. Off-shift and overtime labor 

were used, to the extent practicable to 

make these repairs; and 

(iii) The frequency, amount, and 

duration of the excess emissions 

(including any bypass) were minimized 

to the maximum extent practicable 

during periods of such emissions; and 

(iv) If the excess emissions resulted 

from a bypass of control equipment or 

a process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; and 

(v) All possible steps were taken to 

minimize the impact of the excess 

emissions on ambient air quality, the 

environment, and human health; and 

(vi) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(vii) All of the actions in response to 

the excess emissions were documented 

by properly signed, contemporaneous 

operating logs; and 

(viii) At all times, the facility was 

operated in a manner consistent with 

good practices for minimizing 

emissions; and 

(ix) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the excess emissions resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of excess emissions that were 

the result of the malfunction. 

(2) Notification. The owner or 

operator of the affected source 

experiencing an exceedance of its 

emission limit(s) during a malfunction 

shall notify the Administrator by 

telephone or facsimile (FAX) 

transmission as soon as possible, but no 

later than two business days after the 

initial occurrence of the malfunction or, 

if it is not possible to determine within 

two business days whether the 

malfunction caused or contributed to an 

exceedance, no later than two business 

days after the owner or operator knew 

or should have known that the 

malfunction caused or contributed to an 

exceedance, but, in no event later than 

two business days after the end of the 

averaging period, if it wishes to avail 

itself of an affirmative defense to civil 

penalties for that malfunction. The 

owner or operator seeking to assert an 

affirmative defense shall also submit a 

written report to the Administrator 

within 45 days of the initial occurrence 

of the exceedance of the standard in 

§ 63.9991 to demonstrate, with all 

necessary supporting documentation, 

that it has met the requirements set forth 

in paragraph (s)(1) of this section. The 

owner or operator may seek an 

extension of this deadline for up to 30 

additional days by submitting a written 

request to the Administrator before the 

expiration of the 45 day period. Until a 

request for an extension has been 

approved by the Administrator, the 

owner or operator is subject to the 

requirement to submit such report 

within 45 days of the initial occurrence 

of the exceedance. 

■ 19. Section 60.49Da is amended as 

follows: 

■ a. By revising paragraphs (a)(1) and 

(2). 


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■ b. By revising paragraph (a)(3) 

introductory text. 

■ c. By revising paragraph (a)(3)(ii). 

■ d. By revising paragraph (a)(3)(iii)(B). 

■ e. By adding paragraph (a)(4). 

■ f. By revising paragraph (b) 

introductory text. 

■ g. By revising paragraph (b)(2). 

■ h. By revising paragraph (e). 

■ i. By revising paragraph (k) 

introductory text. 

■ j. By revising paragraph (k)(3). 

■ k. By revising paragraph (l). 

■ l. By removing and reserving 

paragraph (p). 

■ m. By removing and reserving 

paragraph (q). 

■ n. By removing and reserving 

paragraph (r). 

■ o. By revising paragraph (t). 

■ p. By revising paragraph (u)(1)(iii). 

■ q. By revising paragraph (v)(4). 

§ 60.49Da Emission monitoring. 

(a) * * * 

(1) Except as provided for in 

paragraphs (a)(2) and (4) of this section, 

the owner or operator of an affected 

facility subject to an opacity standard, 

shall install, calibrate, maintain, and 

operate a COMS, and record the output 

of the system, for measuring the opacity 

of emissions discharged to the 

atmosphere. If opacity interference due 

to water droplets exists in the stack (for 

example, from the use of an FGD 

system), the opacity is monitored 

upstream of the interference (at the inlet 

to the FGD system). If opacity 

interference is experienced at all 

locations (both at the inlet and outlet of 

the SO2 control system), alternate 

parameters indicative of the PM control 

system’s performance and/or good 

combustion are monitored (subject to 

the approval of the Administrator). 

(2) As an alternative to the monitoring 

requirements in paragraph (a)(1) of this 

section, an owner or operator of an 

affected facility that meets the 

conditions in either paragraph (a)(2)(i), 

(ii), (iii), or (iv) of this section may elect 

to monitor opacity as specified in 

paragraph (a)(3) of this section. 

(i) The affected facility uses a fabric 

filter (baghouse) to meet the standards 

in § 60.42Da and a bag leak detection 

system is installed and operated 

according to the requirements in 

paragraphs § 60.48Da(o)(4)(i) through 

(v); 

(ii) The affected facility burns only 

gaseous or liquid fuels (excluding 

residual oil) with potential SO2

emissions rates of 26 ng/J (0.060 lb/ 

MMBtu) or less, and does not use a postcombustion technology to reduce 

emissions of SO2 or PM; 

(iii) The affected facility meets all of 

the conditions specified in paragraphs 

(a)(2)(iii)(A) through (C) of this section. 

(A) No post-combustion technology 

(except a wet scrubber) is used for 

reducing PM, SO2, or CO emissions; 

(B) Only natural gas, gaseous fuels, or 

fuel oils that contain less than or equal 

to 0.30 weight percent sulfur are 

burned; and 

(C) Emissions of CO discharged to the 

atmosphere are maintained at levels less 

than or equal to 1.4 lb/MWh on a boiler 

operating day average basis as 

demonstrated by the use of a CEMS 

measuring CO emissions according to 

the procedures specified in paragraph 

(u) of this section; or 

(iv) The affected facility uses an ESP 

and uses an ESP predictive model to 

monitor the performance of the ESP 

developed in accordance and operated 

according to the most current 

requirements in section § 60.48Da of 

this part. 

(3) The owner or operator 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. 

* * * * * 

(ii) Except as provided in paragraph 

(a)(3)(iii) or (iv) of this section, the 

owner or operator shall conduct 

subsequent Method 9 of appendix A–4 

of this part performance tests using the 

procedures in paragraph (a)(3)(i) of this 

section according to the applicable 

schedule in paragraphs (a)(3)(ii)(A) 

through (a)(3)(ii)(C) of this section, as 

determined by the most recent Method 

9 of appendix A–4 of this part 

performance test results. 

(A) If the maximum 6-minute average 

opacity is less than or equal to 5 

percent, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 12 

calendar months from the date that the 

most recent performance test was 

conducted or within 45 days of the next 

day that fuel with an opacity standard 

is combusted, whichever is later; 

(B) If the maximum 6-minute average 

opacity is greater than 5 percent but less 

than or equal to 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 3 calendar months 

from the date that the most recent 

performance test was conducted or 

within 45 days of the next day that fuel 

with an opacity standard is combusted, 

whichever is later; or 

(C) If the maximum 6-minute average 

opacity is greater than 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 45 calendar days from 

the date that the most recent 

performance test was conducted. 

(iii) * * * 

(B) If no visible emissions are 

observed for 10 operating days during 

which an opacity standard is applicable, 

observations can be reduced to once 

every 7 operating days during which an 

opacity standard is applicable. If any 

visible emissions are observed, daily 

observations shall be resumed. 

* * * * * 

(4) An owner or operator of an 

affected facility that is subject to an 

opacity standard under § 60.42a(b) is 

not required to operate a COMS 

provided that affected facility meets the 

conditions in either paragraph (a)(4)(i) 

or (ii) of this section. 

(i) The affected facility combusts only 

gaseous fuels and/or liquid fuels 

(excluding residue oil) with a potential 

SO2 emissions rate no greater than 26 

ng/J (0.060 lb/MMBtu), and the unit 

operates according to a written sitespecific monitoring plan approved by 

the permitting authority. This 

monitoring plan must include 

procedures and criteria for establishing 

and monitoring specific parameters for 

the affected facility indicative of 

compliance with the opacity standard. 

For testing performed as part of this sitespecific monitoring plan, the permitting 

authority may require as an alternative 

to the notification and reporting 

requirements specified in §§ 60.8 and 

60.11 that the owner or operator submit 

any deviations with the excess 

emissions report required under 

§ 60.51a(d). 

(ii) The owner or operator of the 

affected facility installs, calibrates, 

operates, and maintains a particulate 

matter continuous parametric 

monitoring system (PM CPMS) 

according to the requirements specified 

in subpart UUUUU of part 63. 

(b) The owner or operator of an 

affected facility shall install, calibrate, 

maintain, and operate a CEMS, and 

record the output of the system, for 

measuring SO2 emissions, except where 

natural gas and/or liquid fuels 

(excluding residual oil) with potential 

SO2 emissions rates of 26 ng/J (0.060 lb/ 


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9458 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

MMBtu) or less are the only fuels 

combusted, as follows: 

* * * * * 

(2) For a facility that qualifies under 

the numerical limit provisions of 

§ 60.43Da, SO2 emissions are only 

monitored as discharged to the 

atmosphere. 

* * * * * 

(e) The CEMS under paragraphs (b), 

(c), and (d) of this section are operated 

and data recorded during all periods of 

operation of the affected facility 

including periods of startup, shutdown, 

and malfunction, except for CEMS 

breakdowns, repairs, calibration checks, 

and zero and span adjustments. 

* * * * * 

(k) The procedures specified in 

paragraphs (k)(1) through (3) of this 

section shall be used to determine gross 

energy output for sources demonstrating 

compliance with an output-based 

standard. 

* * * * * 

(3) For an affected facility generating 

process steam in combination with 

electrical generation, the gross energy 

output is determined according to the 

definition of ‘‘gross energy output’’ 

specified in § 60.41Da that is applicable 

to the affected facility. 

(l) The owner or operator of an 

affected facility demonstrating 

compliance with an output-based 

standard shall install, certify, operate, 

and maintain a continuous flow 

monitoring system meeting the 

requirements of Performance 

Specification 6 of appendix B of this 

part and the calibration drift (CD) 

assessment, relative accuracy test audit 

(RATA), and reporting provisions of 

procedure 1 of appendix F of this part, 

and record the output of the system, for 

measuring the volumetric flow rate of 

exhaust gases discharged to the 

atmosphere; or 

* * * * * 

(t) The owner or operator of an 

affected facility demonstrating 

compliance with the output-based 

emissions limitation under § 60.42Da 

shall install, certify, operate, and 

maintain a CEMS for measuring PM 

emissions according to the requirements 

of paragraph (v) of this section. An 

owner or operator of an affected facility 

demonstrating compliance with the 

input-based emissions limit in 

§ 60.42Da may install, certify, operate, 

and maintain a CEMS for measuring PM 

emissions according to the requirements 

of paragraph (v) of this section. 

(u) * * * 

(1) * * * 

(iii) At a minimum, non-out-of-control 

1-hour CO emissions averages must be 

obtained for at least 90 percent of the 

operating hours on a 30-boiler operating 

day rolling average basis. The 1-hour 

averages are calculated using the data 

points required in § 60.13(h)(2). 

* * * * * 

(v) * * * 

(4) As of January 1, 2012, and within 

90 days after the date of completing 

each performance test, as defined in 

§ 60.8, conducted to demonstrate 

compliance with this subpart, you must 

submit relative accuracy test audit (i.e., 

reference method) data and performance 

test (i.e., compliance test) data, except 

opacity data, electronically to EPA’s 

Central Data Exchange (CDX) by using 

the Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/ert 

tool.html/) or other compatible 

electronic spreadsheet. Only data 

collected using test methods compatible 

with ERT are subject to this requirement 

to be submitted electronically into 

EPA’s WebFire database. 

* * * * * 

■ 20. Section 60.50Da is amended as 

follows: 

■ a. By revising paragraph (b). 

■ b. By removing paragraph (g). 

■ c. By removing paragraph (h). 

■ d. By removing paragraph (i). 

§ 60.50Da Compliance determination 

procedures and methods. 

* * * * * 

(b) In conducting the performance 

tests to determine compliance with the 

PM emissions limits in § 60.42Da, the 

owner or operator shall meet the 

requirements specified in paragraphs 

(b)(1) through (3) of this section. 

(1) The owner or operator shall 

measure filterable PM to determine 

compliance with the applicable PM 

emissions limit in § 60.42Da as specified 

in paragraphs (b)(1)(i) through (ii) of this 

section. 

(i) The dry basis F factor (O2) 

procedures in Method 19 of appendix A 

of this part shall be used to compute the 

emission rate of PM. 

(ii) For the PM concentration, Method 

5 of appendix A of this part shall be 

used for an affected facility that does 

not use a wet FGD. For an affected 

facility that uses a wet FGD, Method 5B 

of appendix A of this part shall be used 

downstream of the wet FGD. 

(A) The sampling time and sample 

volume for each run shall be at least 120 

minutes and 1.70 dscm (60 dscf). The 

probe and filter holder heating system 

in the sampling train may be set to 

provide an average gas temperature of 

no greater than 160 ± 14 °C (320 ± 

25 °F). 

(B) For each particulate run, the 

emission rate correction factor, 

integrated or grab sampling and analysis 

procedures of Method 3B of appendix A 

of this part shall be used to determine 

the O2 concentration. The O2 sample 

shall be obtained simultaneously with, 

and at the same traverse points as, the 

particulate run. If the particulate run 

has more than 12 traverse points, the O2

traverse points may be reduced to 12 

provided that Method 1 of appendix A 

of this part is used to locate the 12 O2

traverse points. If the grab sampling 

procedure is used, the O2 concentration 

for the run shall be the arithmetic mean 

of the sample O2 concentrations at all 

traverse points. 

(2) In conjunction with a performance 

test performed according to the 

requirements in paragraph (b)(1) of this 

section, the owner or operator of an 

affected facility for which construction, 

reconstruction, or modification 

commenced after May 3, 2011, shall 

measure condensable PM using Method 

202 of appendix M of part 51. 

(3) Method 9 of appendix A of this 

part and the procedures in § 60.11 shall 

be used to determine opacity. 

* * * * * 

■ 21. Section 60.51Da is amended as 

follows: 

■ a. By revising paragraph (a). 

■ b. By revising paragraph (b)(5). 

■ c. By revising paragraph (d). 

■ d. By removing and reserving 

paragraph (g). 

■ e. By revising paragraph (k). 

§ 60.51Da Reporting requirements. 

(a) For SO2, NOX, PM, and NOX plus 

CO emissions, the performance test data 

from the initial and subsequent 

performance test and from the 

performance evaluation of the 

continuous monitors (including the 

transmissometer) must be reported to 

the Administrator. 

(b) * * * 

(5) Identification of the times when 

emissions data have been excluded from 

the calculation of average emission rates 

because of startup, shutdown, or 

malfunction. 

* * * * * 

(d) In addition to the applicable 

requirements in § 60.7, the owner or 

operator of an affected facility subject to 

the opacity limits in § 60.43c(c) and 

conducting performance tests using 

Method 9 of appendix A–4 of this part 

shall submit excess emission reports for 

any excess emissions from the affected 

facility that occur during the reporting 

period and maintain records according 

to the requirements specified in 

paragraph (d)(1) of this section. 

(1) For each performance test 

conducted using Method 9 of appendix 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9459 

A–4 of this part, the owner or operator 

shall keep the records including the 

information specified in paragraphs 

(d)(1)(i) through (iii) of this section. 

(i) Dates and time intervals of all 

opacity observation periods; 

(ii) Name, affiliation, and copy of 

current visible emission reading 

certification for each visible emission 

observer participating in the 

performance test; and 

(iii) Copies of all visible emission 

observer opacity field data sheets. 

(2) [Reserved] 

* * * * * 

(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) and (i) of this section. 

The format of each quarterly electronic 

report shall be coordinated with the 

permitting authority. The electronic 

report(s) shall be submitted no later 

than 30 days after the end of the 

calendar quarter and shall be 

accompanied by a certification 

statement from the owner or operator, 

indicating whether compliance with the 

applicable emission standards and 

minimum data requirements of this 

subpart was achieved during the 

reporting period. 

§ 60.52Da [Amended] 

■ 22. Section 60.52Da is amended by 

removing and reserving paragraph (a). 

Subpart Db—[Amended] 

■ 23. Section 60.40b is amended as 

follows: 

■ a. By revising paragraph (c). 

■ b. By revising paragraph (h). 

■ c. By revising paragraph (i). 

■ d. By adding paragraph (1). 

■ e. By adding paragraph (m). 

§ 60.40b Applicability and delegation of 

authority. 

* * * * * 

(c) Affected facilities that also meet 

the applicability requirements under 

subpart J or subpart Ja of this part are 

subject to the PM and NOX standards 

under this subpart and the SO2

standards under subpart J or subpart Ja 

of this part, as applicable. 

* * * * * 

(h) Any affected facility that meets the 

applicability requirements and is 

subject to subpart Ea, subpart Eb, 

subpart AAAA, or subpart CCCC of this 

part is not subject to this subpart. 

(i) Affected facilities (i.e., heat 

recovery steam generators) that are 

associated with stationary combustion 

turbines and that meet the applicability 

requirements of subpart KKKK of this 

part are not subject to this subpart. This 

subpart will continue to apply to all 

other affected facilities (i.e. heat 

recovery steam generators with duct 

burners) that are capable of combusting 

more than 29 MW (100 MMBtu/h) heat 

input of fossil fuel. If the affected 

facility (i.e. heat recovery steam 

generator) is subject to this subpart, only 

emissions resulting from combustion of 

fuels in the steam generating unit are 

subject to this subpart. (The stationary 

combustion turbine emissions are 

subject to subpart GG or KKKK, as 

applicable, of this part.) 

* * * * * 

(l) Affected facilities that also meet 

the applicability requirements under 

subpart BB of this part (Standards of 

Performance for Kraft Pulp Mills) are 

subject to the SO2 and NOX standards 

under this subpart and the PM 

standards under subpart BB. 

(m) Temporary boilers are not subject 

to this subpart. 

24. Section 60.41b is amended by 

revising the definition of ‘‘distillate oil’’, 

and adding the definition of ‘‘temporary 

boiler’’ in alphabetical order to read as 

follows: 

§ 60.41b Definitions. 

* * * * * 

Distillate oil means fuel oils that 

contain 0.05 weight percent nitrogen or 

less and comply with the specifications 

for fuel oil numbers 1 and 2, as defined 

by the American Society of Testing and 

Materials in ASTM D396 (incorporated 

by reference, see § 60.17), diesel fuel oil 

numbers 1 and 2, as defined by the 

American Society for Testing and 

Materials in ASTM D975 (incorporated 

by reference, see § 60.17), kerosine, as 

defined by the American Society of 

Testing and Materials in ASTM D3699 

(incorporated by reference, see § 60.17), 

biodiesel as defined by the American 

Society of Testing and Materials in 

ASTM D6751 (incorporated by 

reference, see § 60.17), or biodiesel 

blends as defined by the American 

Society of Testing and Materials in 

ASTM D7467 (incorporated by 

reference, see § 60.17). 

* * * * * 

Temporary boiler means any gaseous 

or liquid fuel-fired steam generating 

unit that is designed to, and is capable 

of, being carried or moved from one 

location to another by means of, for 

example, wheels, skids, carrying 

handles, dollies, trailers, or platforms. A 

steam generating unit is not a temporary 

boiler if any one of the following 

conditions exists: 

(1) The equipment is attached to a 

foundation. 

(2) The steam generating unit or a 

replacement remains at a location for 

more than 180 consecutive days. Any 

temporary boiler that replaces a 

temporary boiler at a location and 

performs the same or similar function 

will be included in calculating the 

consecutive time period. 

(3) The equipment is located at a 

seasonal facility and operates during the 

full annual operating period of the 

seasonal facility, remains at the facility 

for at least 2 years, and operates at that 

facility for at least 3 months each year. 

(4) The equipment is moved from one 

location to another in an attempt to 

circumvent the residence time 

requirements of this definition. 

* * * * * 

■ 25. Section 60.43b is amended by 

revising paragraph (f) to read as follows: 

§ 60.43b Standard for particulate matter 

(PM). 

* * * * * 

(f) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that combusts coal, oil, wood, or 

mixtures of these fuels with any other 

fuels shall cause to be discharged into 

the atmosphere any gases that exhibit 

greater than 20 percent opacity (6- 

minute average), except for one 6- 

minute period per hour of not more than 

27 percent opacity. An owner or 

operator of an affected facility that 

elects to install, calibrate, maintain, and 

operate a continuous emissions 

monitoring system (CEMS) for 

measuring PM emissions according to 

the requirements of this subpart and is 

subject to a federally enforceable PM 

limit of 0.030 lb/MMBtu or less is 

exempt from the opacity standard 

specified in this paragraph. 

* * * * * 

■ 26. Section 60.44b is amended as 

follows: 

■ a. The section heading is revised. 

■ b. By revising paragraph (b) 

introductory text. 

■ c. By revising paragraph (c). 

■ d. By revising paragraph (d). 

■ e. By revising paragraph (e). 

■ f. By revising paragraph (l)(1). 

§ 60.44b Standard for nitrogen oxides 

(NOX). 

* * * * * 

(b) Except as provided under 

paragraphs (k) and (l) of this section, on 

and after the date on which the initial 

performance test is completed or is 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 


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9460 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

simultaneously combusts mixtures of 

only coal, oil, or natural gas shall cause 

to be discharged into the atmosphere 

from that affected facility any gases that 

contain NOX in excess of a limit 

determined by the use of the following 

formula: 

* * * * * 

(c) Except as provided under 

paragraph (d) and (l) of this section, on 

and after the date on which the initial 

performance test is completed or is 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

simultaneously combusts coal or oil, 

natural gas (or any combination of the 

three), and wood, or any other fuel shall 

cause to be discharged into the 

atmosphere any gases that contain NOX

in excess of the emission limit for the 

coal, oil, natural gas (or any 

combination of the three), combusted in 

the affected facility, as determined 

pursuant to paragraph (a) or (b) of this 

section. This standard does not apply to 

an affected facility that is subject to and 

in compliance with a federally 

enforceable requirement that limits 

operation of the affected facility to an 

annual capacity factor of 10 percent 

(0.10) or less for coal, oil, natural gas (or 

any combination of the three). 

(d) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that simultaneously combusts natural 

gas and/or distillate oil with a potential 

SO2 emissions rate of 26 ng/J (0.060 lb/ 

MMBtu) or less with wood, municipaltype solid waste, or other solid fuel, 

except coal, shall cause to be discharged 

into the atmosphere from that affected 

facility any gases that contain NOX in 

excess of 130 ng/J (0.30 lb/MMBtu) heat 

input unless the affected facility has an 

annual capacity factor for natural gas, 

distillate oil, or a mixture of these fuels 

of 10 percent (0.10) or less and is subject 

to a federally enforceable requirement 

that limits operation of the affected 

facility to an annual capacity factor of 

10 percent (0.10) or less for natural gas, 

distillate oil, or a mixture of these fuels. 

(e) Except as provided under 

paragraph (l) of this section, on and after 

the date on which the initial 

performance test is completed or is 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

simultaneously combusts only coal, oil, 

or natural gas with byproduct/waste 

shall cause to be discharged into the 

atmosphere any gases that contain NOX

in excess of the emission limit 

determined by the following formula 

unless the affected facility has an 

annual capacity factor for coal, oil, and 

natural gas of 10 percent (0.10) or less 

and is subject to a federally enforceable 

requirement that limits operation of the 

affected facility to an annual capacity 

factor of 10 percent (0.10) or less: 

* * * * * 

(l) * * * 

(1) 86 ng/J (0.20 lb/MMBtu) heat input 

if the affected facility combusts coal, oil, 

or natural gas (or any combination of the 

three), alone or with any other fuels. 

The affected facility is not subject to this 

limit if it is subject to and in compliance 

with a federally enforceable requirement 

that limits operation of the facility to an 

annual capacity factor of 10 percent 

(0.10) or less for coal, oil, and natural 

gas (or any combination of the three); or 

* * * * * 

■ 27. Section 60.46b is amended by 

revising paragraph (j)(14) to read as 

follows: 

§ 60.46b Compliance and performance test 

methods and procedures for particulate 

matter and nitrogen oxides. 

* * * * * 

(j) * * * 

(14) As of January 1, 2012, and within 

90 days after the date of completing 

each performance test, as defined in 

§ 60.8, 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. 

■ 28. Section 60.48b is amended as 

follows: 

■ a. By revising paragraph (a) 

introductory text. 

■ b. By revising paragraphs (a)(1)(i) 

through (iii) . 

■ c. By revising paragraph (a)(2)(ii). 

■ d. By revising paragraph (j) 

introductory text. 

■ e. By revising paragraph (j)(5). 

■ f. By revising paragraph (j)(6). 

■ g. By adding paragraph (j)(7). 

■ h. By adding paragraph (l). 

§ 60.48b Emission monitoring for 

particulate matter and nitrogen oxides. 

(a) Except as provided in paragraph (j) 

of this section, the owner or operator of 

an affected facility subject to the opacity 

standard under § 60.43b shall install, 

calibrate, maintain, and operate a 

continuous opacity monitoring systems 

(COMS) for measuring the opacity of 

emissions discharged to the atmosphere 

and record the output of the system. The 

owner or operator of an affected facility 

subject to an opacity standard under 

§ 60.43b and meeting the conditions 

under paragraphs (j)(1), (2), (3), (4), (5), 

or (6) of this section who elects not to 

use a COMS shall conduct a 

performance test using Method 9 of 

appendix A–4 of this part and the 

procedures in § 60.11 to demonstrate 

compliance with the applicable limit in 

§ 60.43b by April 29, 2011, within 45 

days of stopping use of an existing 

COMS, or within 180 days after initial 

startup of the facility, whichever is later, 

and shall comply with either paragraphs 

(a)(1), (a)(2), or (a)(3) of this section. The 

observation period for Method 9 of 

appendix A–4 of this part performance 

tests may be reduced from 3 hours to 60 

minutes if all 6-minute averages are less 

than 10 percent and all individual 15- 

second observations are less than or 

equal to 20 percent during the initial 60 

minutes of observation. 

(1) * * * 

(i) If no visible emissions are 

observed, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 12 

calendar months from the date that the 

most recent performance test was 

conducted or within 45 days of the next 

day that fuel with an opacity standard 

is combusted, whichever is later; 

(ii) If visible emissions are observed 

but the maximum 6-minute average 

opacity is less than or equal to 5 

percent, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 6 

calendar months from the date that the 

most recent performance test was 

conducted or within 45 days of the next 

day that fuel with an opacity standard 

is combusted, whichever is later; 

(iii) If the maximum 6-minute average 

opacity is greater than 5 percent but less 

than or equal to 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 3 calendar months 

from the date that the most recent 

performance test was conducted or 

within 45 days of the next day that fuel 

with an opacity standard is combusted, 

whichever is later; or 

* * * * * 

(2) * * * 

(ii) If no visible emissions are 

observed for 10 operating days during 

which an opacity standard is applicable, 

observations can be reduced to once 

every 7 operating days during which an 


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opacity standard is applicable. If any 

visible emissions are observed, daily 

observations shall be resumed. 

* * * * * 

(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: 

* * * * * 

(5) The affected facility uses a bag 

leak detection system to monitor the 

performance of a fabric filter (baghouse) 

according to the most current 

requirements in section § 60.48Da of 

this part; or 

(6) The affected facility uses an ESP 

as the primary PM control device and 

uses an ESP predictive model to 

monitor the performance of the ESP 

developed in accordance and operated 

according to the most current 

requirements in section § 60.48Da of 

this part; or 

(7) The affected facility burns only 

gaseous fuels or fuel oils that contain 

less than or equal to 0.30 weight percent 

sulfur and operates according to a 

written site-specific monitoring plan 

approved by the permitting authority. 

This monitoring plan must include 

procedures and criteria for establishing 

and monitoring specific parameters for 

the affected facility indicative of 

compliance with the opacity standard. 

* * * * * 

(l) An owner or operator of an affected 

facility that is subject to an opacity 

standard under § 60.43b(f) is not 

required to operate a COMS provided 

that the unit burns only gaseous fuels 

and/or liquid fuels (excluding residue 

oil) with a potential SO2 emissions rate 

no greater than 26 ng/J (0.060 lb/ 

MMBtu), and the unit operates 

according to a written site-specific 

monitoring plan approved by the 

permitting authority is not required to 

operate a COMS. This monitoring plan 

must include procedures and criteria for 

establishing and monitoring specific 

parameters for the affected facility 

indicative of compliance with the 

opacity standard. For testing performed 

as part of this site-specific monitoring 

plan, the permitting authority may 

require as an alternative to the 

notification and reporting requirements 

specified in §§ 60.8 and 60.11 that the 

owner or operator submit any deviations 

with the excess emissions report 

required under § 60.49b(h). 

■ 29. Section 60.49b is amended by 

revising paragraph (r)(1) to read as 

follows. 

§ 60.49b Reporting and recordkeeping 

requirements. 

* * * * * 

(r) * * * 

(1) The owner or operator of an 

affected facility who elects to 

demonstrate that the affected facility 

combusts only very low sulfur oil, 

natural gas, wood, a mixture of these 

fuels, or any of these fuels (or a mixture 

of these fuels) in combination with 

other fuels that are known to contain an 

insignificant amount of sulfur in 

§ 60.42b(j) or § 60.42b(k) shall obtain 

and maintain at the affected facility fuel 

receipts (such as a current, valid 

purchase contract, tariff sheet, or 

transportation contract) from the fuel 

supplier that certify that the oil meets 

the definition of distillate oil and 

gaseous fuel meets the definition of 

natural gas as defined in § 60.41b and 

the applicable sulfur limit. For the 

purposes of this section, the distillate 

oil need not meet the fuel nitrogen 

content specification in the definition of 

distillate oil. Reports shall be submitted 

to the Administrator certifying that only 

very low sulfur oil meeting this 

definition, natural gas, wood, and/or 

other fuels that are known to contain 

insignificant amounts of sulfur were 

combusted in the affected facility during 

the reporting period; or 

* * * * * 

Subpart Dc—[Amended] 

■ 30. Section 60.40c is amended as 

follows: 

■ a. By revising paragraph (a). 

■ b. By revising paragraph (e). 

■ c. By revising paragraph (f). 

■ d. By revising paragraph (g). 

■ e. By adding paragraph (h). 

■ f. By adding paragraph (i). 

§ 60.40c Applicability and delegation of 

authority. 

(a) Except as provided in paragraphs 

(d), (e), (f), and (g) of this section, the 

affected facility to which this subpart 

applies is each steam generating unit for 

which construction, modification, or 

reconstruction is commenced after June 

9, 1989 and that has a maximum design 

heat input capacity of 29 megawatts 

(MW) (100 million British thermal units 

per hour (MMBtu/h)) or less, but greater 

than or equal to 2.9 MW (10 MMBtu/h). 

* * * * * 

(e) Affected facilities (i.e. heat 

recovery steam generators and fuel 

heaters) that are associated with 

stationary combustion turbines and 

meet the applicability requirements of 

subpart KKKK of this part are not 

subject to this subpart. This subpart will 

continue to apply to all other heat 

recovery steam generators, fuel heaters, 

and other affected facilities that are 

capable of combusting more than or 

equal to 2.9 MW (10 MMBtu/h) heat 

input of fossil fuel but less than or equal 

to 29 MW (100 MMBtu/h) heat input of 

fossil fuel. If the heat recovery steam 

generator, fuel heater, or other affected 

facility is subject to this subpart, only 

emissions resulting from combustion of 

fuels in the steam generating unit are 

subject to this subpart. (The stationary 

combustion turbine emissions are 

subject to subpart GG or KKKK, as 

applicable, of this part.) 

(f) Any affected facility that meets the 

applicability requirements of and is 

subject to subpart AAAA or subpart 

CCCC of this part is not subject to this 

subpart. 

(g) Any facility that meets the 

applicability requirements and is 

subject to an EPA approved State or 

Federal section 111(d)/129 plan 

implementing subpart BBBB of this part 

is not subject to this subpart. 

(h) Affected facilities that also meet 

the applicability requirements under 

subpart J or subpart Ja of this part are 

subject to the PM and NOX standards 

under this subpart and the SO2

standards under subpart J or subpart Ja 

of this part, as applicable. 

(i) Temporary boilers are not subject 

to this subpart. 

■ 31. Section 60.41c is amended as 

follows: 

■ a. By removing the definition of 

‘‘Cogeneration.’’ 

■ b. By revising the definition of 

‘‘Distillate oil.’’ 

■ c. By adding a definition of 

‘‘Temporary boiler’’ in alphabetical 

order. 

§ 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), kerosine, as 

defined by the American Society of 

Testing and Materials in ASTM D3699 

(incorporated by reference, see § 60.17), 

biodiesel as defined by the American 

Society of Testing and Materials in 

ASTM D6751 (incorporated by 

reference, see § 60.17), or biodiesel 

blends as defined by the American 

Society of Testing and Materials in 

ASTM D7467 (incorporated by 

reference, see § 60.17). 

* * * * * 


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Temporary boiler means a steam 

generating unit that combusts natural 

gas or distillate oil with a potential SO2

emissions rate no greater than 26 ng/J 

(0.060 lb/MMBtu), and the unit is 

designed to, and is capable of, being 

carried or moved from one location to 

another by means of, for example, 

wheels, skids, carrying handles, dollies, 

trailers, or platforms. A steam 

generating unit is not a temporary boiler 

if any one of the following conditions 

exists: 

(1) The equipment is attached to a 

foundation. 

(2) The steam generating unit or a 

replacement remains at a location for 

more than 180 consecutive days. Any 

temporary boiler that replaces a 

temporary boiler at a location and 

performs the same or similar function 

will be included in calculating the 

consecutive time period. 

(3) The equipment is located at a 

seasonal facility and operates during the 

full annual operating period of the 

seasonal facility, remains at the facility 

for at least 2 years, and operates at that 

facility for at least 3 months each year. 

(4) The equipment is moved from one 

location to another in an attempt to 

circumvent the residence time 

requirements of this definition. 

* * * * * 

■ 32. Section 60.42c is amended as 

follows: 

■ a. By revising paragraph (c)(1) and (3). 

■ b. By revising paragraph (d). 

■ c. By revising paragraph (e)(1)(ii). 

■ d. By revising paragraph (h) 

introductory text. 

■ e. By revising paragraph (h)(3). 

■ f. By adding paragraph (h)(4). 

§ 60.42c Standard for sulfur dioxide (SO2). 

* * * * * 

(c) * * * 

(1) Affected facilities that have a heat 

input capacity of 22 MW (75 MMBtu/h) 

or less; 

* * * * * 

(3) Affected facilities located in a 

noncontinental area; or 

* * * * * 

(d) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

combusts oil shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain SO2 in excess of 215 ng/J (0.50 

lb/MMBtu) heat input from oil; or, as an 

alternative, no owner or operator of an 

affected facility that combusts oil shall 

combust oil in the affected facility that 

contains greater than 0.5 weight percent 

sulfur. The percent reduction 

requirements are not applicable to 

affected facilities under this paragraph. 

(e) * * * 

(1) * * * 

(ii) Has a heat input capacity greater 

than 22 MW (75 MMBtu/h); and 

* * * * * 

(h) For affected facilities listed under 

paragraphs (h)(1), (2), (3), or (4) of this 

section, compliance with the emission 

limits or fuel oil sulfur limits under this 

section may be determined 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/h). 

(4) Other fuels-fired affected facilities 

with heat input capacities between 2.9 

and 8.7 MW (10 and 30 MMBtu/h). 

* * * * * 

■ 33. Section 60.43c is amended as 

follows: 

■ a. By revising paragraph (a) 

introductory text. 

■ b. By revising paragraph (b) 

introductory text. 

■ c. By revising paragraph (c). 

■ d. By revising paragraphs (e)(1), (3), 

and (4). 

§ 60.43c Standard for particulate matter 

(PM). 

(a) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification on or 

before February 28, 2005, that combusts 

coal or combusts mixtures of coal with 

other fuels and has a heat input capacity 

of 8.7 MW (30 MMBtu/h) or greater, 

shall cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain PM in excess of 

the following emission limits: 

* * * * * 

(b) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification on or 

before February 28, 2005, that combusts 

wood or combusts mixtures of wood 

with other fuels (except coal) and has a 

heat input capacity of 8.7 MW (30 

MMBtu/h) or greater, shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain PM in excess of the following 

emissions limits: 

* * * * * 

(c) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

combusts coal, wood, or oil and has a 

heat input capacity of 8.7 MW (30 

MMBtu/h) or greater shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

exhibit greater than 20 percent opacity 

(6-minute average), except for one 6- 

minute period per hour of not more than 

27 percent opacity. Owners and 

operators of an affected facility that 

elect to install, calibrate, maintain, and 

operate a continuous emissions 

monitoring system (CEMS) for 

measuring PM emissions according to 

the requirements of this subpart and are 

subject to a federally enforceable PM 

limit of 0.030 lb/MMBtu or less are 

exempt from the opacity standard 

specified in this paragraph (c). 

* * * * * 

(e)(1) On and after the date on which 

the initial performance test is completed 

or is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that commences construction, 

reconstruction, or modification after 

February 28, 2005, and that combusts 

coal, oil, wood, a mixture of these fuels, 

or a mixture of these fuels with any 

other fuels and has a heat input capacity 

of 8.7 MW (30 MMBtu/h) or greater 

shall cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain PM in excess of 

13 ng/J (0.030 lb/MMBtu) heat input, 

except as provided in paragraphs (e)(2), 

(e)(3), and (e)(4) of this section. 

* * * * * 

(3) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that commences modification after 

February 28, 2005, and that combusts 

over 30 percent wood (by heat input) on 

an annual basis and has a heat input 

capacity of 8.7 MW (30 MMBtu/h) or 

greater shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain PM in 

excess of 43 ng/J (0.10 lb/MMBtu) heat 

input. 

(4) An owner or operator of an 

affected facility that commences 

construction, reconstruction, or 

modification after February 28, 2005, 

and that combusts only oil that contains 

no more than 0.50 weight percent sulfur 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9463 

or a mixture of 0.50 weight percent 

sulfur oil with other fuels not subject to 

a PM standard under § 60.43c and not 

using a post-combustion technology 

(except a wet scrubber) to reduce PM or 

SO2 emissions is not subject to the PM 

limit in this section. 

■ 34. Section 60.45c is amended as 

follows: 

■ a. By revising paragraph (c)(14). 

■ b. By revising paragraph (d). 

§ 60.45c Compliance and performance test 

methods and procedures for particulate 

matter. 

* * * * * 

(c) * * * 

(14) As of January 1, 2012, and within 

90 days after the date of completing 

each performance test, as defined in 

§ 60.8, conducted to demonstrate 

compliance with this subpart, you must 

submit relative accuracy test audit (i.e., 

reference method) data and performance 

test (i.e., compliance test) data, except 

opacity data, electronically to EPA’s 

Central Data Exchange (CDX) by using 

the Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/ert 

tool.html/) or other compatible 

electronic spreadsheet. Only data 

collected using test methods compatible 

with ERT are subject to this requirement 

to be submitted electronically into 

EPA’s WebFIRE database. 

(d) The owner or operator of an 

affected facility seeking to demonstrate 

compliance under § 60.43c(e)(4) shall 

follow the applicable procedures under 

§ 60.48c(f). For residual oil-fired 

affected facilities, fuel supplier 

certifications are only allowed for 

facilities with heat input capacities 

between 2.9 and 8.7 MW (10 to 30 

MMBtu/h). 

■ 35. Section 60.47c is amended as 

follows: 

■ a. By revising paragraph (a) 

introductory text. 

■ b. By revising paragraphs (a)(1)(i) 

through (iii). 

■ c. By revising paragraph (a)(2)(ii). 

■ d. By revising paragraph (f). 

■ e. By removing paragraph (g). 

§ 60.47c Emission monitoring for 

particulate matter. 

(a) Except as provided in paragraphs 

(c), (d), (e), and (f) of this section, the 

owner or operator of an affected facility 

combusting coal, oil, or wood that is 

subject to the opacity standards under 

§ 60.43c shall install, calibrate, 

maintain, and operate a continuous 

opacity monitoring system (COMS) for 

measuring the opacity of the emissions 

discharged to the atmosphere and 

record the output of the system. The 

owner or operator of an affected facility 

subject to an opacity standard in 

§ 60.43c(c) that is not required to use a 

COMS due to paragraphs (c), (d), (e), or 

(f) of this section that elects not to use 

a COMS shall conduct a performance 

test using Method 9 of appendix A–4 of 

this part and the procedures in § 60.11 

to demonstrate compliance with the 

applicable limit in § 60.43c by April 29, 

2011, within 45 days of stopping use of 

an existing COMS, or within 180 days 

after initial startup of the facility, 

whichever is later, and shall comply 

with either paragraphs (a)(1), (a)(2), or 

(a)(3) of this section. The observation 

period for Method 9 of appendix A–4 of 

this part performance tests may be 

reduced from 3 hours to 60 minutes if 

all 6-minute averages are less than 10 

percent and all individual 15-second 

observations are less than or equal to 20 

percent during the initial 60 minutes of 

observation. 

(1) * * * 

(i) If no visible emissions are 

observed, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 12 

calendar months from the date that the 

most recent performance test was 

conducted or within 45 days of the next 

day that fuel with an opacity standard 

is combusted, whichever is later; 

(ii) If visible emissions are observed 

but the maximum 6-minute average 

opacity is less than or equal to 5 

percent, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 6 

calendar months from the date that the 

most recent performance test was 

conducted or within 45 days of the next 

day that fuel with an opacity standard 

is combusted, whichever is later; 

(iii) If the maximum 6-minute average 

opacity is greater than 5 percent but less 

than or equal to 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 3 calendar months 

from the date that the most recent 

performance test was conducted or 

within 45 days of the next day that fuel 

with an opacity standard is combusted, 

whichever is later; or 

* * * * * 

(2) * * * 

(ii) If no visible emissions are 

observed for 10 operating days during 

which an opacity standard is applicable, 

observations can be reduced to once 

every 7 operating days during which an 

opacity standard is applicable. If any 

visible emissions are observed, daily 

observations shall be resumed. 

* * * * * 

(f) An owner or operator of an affected 

facility that is subject to an opacity 

standard in § 60.43c(c) is not required to 

operate a COMS provided that the 

affected facility meets the conditions in 

either paragraphs (f)(1), (2), or (3) of this 

section. 

(1) The affected facility uses a fabric 

filter (baghouse) as the primary PM 

control device and, the owner or 

operator operates a bag leak detection 

system to monitor the performance of 

the fabric filter according to the 

requirements in section § 60.48Da of 

this part. 

(2) The affected facility uses an ESP 

as the primary PM control device, and 

the owner or operator uses an ESP 

predictive model to monitor the 

performance of the ESP developed in 

accordance and operated according to 

the requirements in section § 60.48Da of 

this part. 

(3) The affected facility burns only 

gaseous fuels and/or fuel oils that 

contain no greater than 0.5 weight 

percent sulfur, and the owner or 

operator operates the unit according to 

a written site-specific monitoring plan 

approved by the permitting authority. 

This monitoring plan must include 

procedures and criteria for establishing 

and monitoring specific parameters for 

the affected facility indicative of 

compliance with the opacity standard. 

For testing performed as part of this sitespecific monitoring plan, the permitting 

authority may require as an alternative 

to the notification and reporting 

requirements specified in §§ 60.8 and 

60.11 that the owner or operator submit 

any deviations with the excess 

emissions report required under 

§ 60.48c(c). 

Subpart HHHH—[Removed and 

Reserved] 

■ 36. Subpart HHHH is removed and 

reserved. 

PART 63—[AMENDED] 

■ 37. The authority citation for 40 CFR 

Part 63 continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart A—[Amended] 

■ 38. Section 63.14 is amended as 

follows: 

■ a. By adding paragraphs (b)(19) and 

(20). 

■ b. By adding paragraphs (b)(22) and 

(23). 

■ c. By adding paragraphs (b)(69) 

through (72). 

■ d. By revising paragraph (i)(1). 

§ 63.14 Incorporation by reference. 

* * * * * 

(b) * * * 


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(19) ASTM D95–05 (Reapproved 

2010), Standard Test Method for Water 

in Petroleum Products and Bituminous 

Materials by Distillation, approved May 

1, 2010, IBR approved for 

§ 63.10005(i)(4)(i). 

(20) ASTM Method D388–05, 

Standard Classification of Coals by 

Rank, approved September 15, 2005, 

IBR approved for § 63.10042. 

* * * * * 

(22) ASTM Method D396–10, 

Standard Specification for Fuel Oils, 

including Appendix X1, approved 

October 1, 2010, IBR approved for 

§ 63.10042. 

(23) ASTM D4006–11, Standard Test 

Method for Water in Crude Oil by 

Distillation, including Annex A1 and 

Appendix X1, approved June 1, 2011, 

IBR approved for § 63.10005(i)(4)(ii). 

* * * * * 

(69) ASTM D4057–06 (Reapproved 

2011), Standard Practice for Manual 

Sampling of Petroleum and Petroleum 

Products, including Annex A1, 

approved June 1, 2011, IBR approved for 

§ 63.10005(i)(4)(iv). 

(70) ASTM D4177–95 (Reapproved 

2010), Standard Practice for Automatic 

Sampling of Petroleum and Petroleum 

Products, including Annexes A1 

through A6 and Appendices X1 and X2, 

approved May 1, 2010, IBR approved for 

§ 63.10005(i)(4)(iii). 

(71) ASTM D6348–03 (Reapproved 

2010), Standard Test Method for 

Determination of Gaseous Compounds 

by Extractive Direct Interface Fourier 

Transform Infrared (FTIR) Spectroscopy, 

including Annexes A1 through A8, 

approved October 1, 2010, IBR approved 

for table 1 to subpart UUUUU of this 

part, table 2 to subpart UUUUU of this 

part, table 5 to subpart UUUUU of this 

part, and appendix B to subpart 

UUUUU of this part. 

(72) ASTM D6784–02 (Reapproved 

2008), Standard Test Method for 

Elemental, Oxidized, Particle-Bound 

and Total Mercury in Flue Gas 

Generated from Coal-Fired Stationary 

Sources (Ontario Hydro Method), 

approved April 1, 2008, IBR approved 

for table 5 to subpart UUUUU of this 

part, and appendix A to subpart 

UUUUU of this part. 

* * * * * 

(i) * * * 

(1) ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses [part 

10, Instruments and Apparatus],’’ IBR 

approved for §§ 63.309(k)(1)(iii), 

63.865(b), 63.3166(a)(3), 

63.3360(e)(1)(iii), 63.3545(a)(3), 

63.3555(a)(3), 63.4166(a)(3), 

63.4362(a)(3), 63.4766(a)(3), 

63.4965(a)(3), 63.5160(d)(1)(iii), 

63.9307(c)(2), 63.9323(a)(3), 

63.11148(e)(3)(iii), 63.11155(e)(3), 

63.11162(f)(3)(iii) and (f)(4), 

63.11163(g)(1)(iii) and (g)(2), 

63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), 

table 5 to subpart DDDDD of this part, 

table 1 to subpart ZZZZZ of this part, 

table 4 to subpart JJJJJJ of this part, and 

table 5 to subpart UUUUU of this part. 

* * * * * 

■ 39. Part 63 is amended by adding 

subpart UUUUU to read as follows: 

Subpart UUUUU—National Emission 

Standards for Hazardous Air 

Pollutants: Coal- and Oil-Fired Electric 

Utility Steam Generating Units 

Sec. 

What This Subpart Covers 

63.9980 What is the purpose of this 

subpart? 

63.9981 Am I subject to this subpart? 

63.9982 What is the affected source of this 

subpart? 

63.9983 Are any EGUs not subject to this 

subpart? 

63.9984 When do I have to comply with 

this subpart? 

63.9985 What is a new EGU? 

Emission Limitations and Work Practice 

Standards 

63.9990 What are the subcategories of 

EGUs? 

63.9991 What emission limitations, work 

practice standards, and operating limits 

must I meet? 

General Compliance Requirements 

63.10000 What are my general requirements 

for complying with this subpart? 

63.10001 Affirmative defense for 

exceedence of emission limit during 

malfunction. 

Testing and Initial Compliance 

Requirements 

63.10005 What are my initial compliance 

requirements and by what date must I 

conduct them? 

63.10006 When must I conduct subsequent 

performance tests or tune-ups? 

63.10007 What methods and other 

procedures must I use for the 

performance tests? 

63.10008 [Reserved] 

63.10009 May I use emissions averaging to 

comply with this subpart? 

63.10010 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

63.10011 How do I demonstrate initial 

compliance with the emission 

limitations and work practice standards? 

Continuous Compliance Requirements 

63.10020 How do I monitor and collect data 

to demonstrate continuous compliance? 

63.10021 How do I demonstrate continuous 

compliance with the emission 

limitations, operating limits, and work 

practice standards? 

63.10022 How do I demonstrate continuous 

compliance under the emissions 

averaging provision? 

63.10023 How do I establish my PM CPMS 

operating limit and determine 

compliance with it? 

Notifications, Reports, and Records 

63.10030 What notifications must I submit 

and when? 

63.10031 What reports must I submit and 

when? 

63.10032 What records must I keep? 

63.10033 In what form and how long must 

I keep my records? 

Other Requirements and Information 

63.10040 What parts of the General 

Provisions apply to me? 

63.10041 Who implements and enforces 

this subpart? 

63.10042 What definitions apply to this 

subpart? 

Tables to Subpart UUUUU of Part 63 

Table 1 to Subpart UUUUU of Part 63— 

Emission Limits for New or 

Reconstructed EGUs 

Table 2 to Subpart UUUUU of Part 63— 

Emission Limits for Existing EGUs 

Table 3 to Subpart UUUUU of Part 63—Work 

Practice Standards 

Table 4 to Subpart UUUUU of Part 63— 

Operating Limits for EGUs 

Table 5 to Subpart UUUUU of Part 63— 

Performance Testing Requirements 

Table 6 to Subpart UUUUU of Part 63— 

Establishing PM CPMS Operating Limits 

Table 7 to Subpart UUUUU of Part 63— 

Demonstrating Continuous Compliance 

Table 8 to Subpart UUUUU of Part 63— 

Reporting Requirements 

Table 9 to Subpart UUUUU of Part 63— 

Applicability of General Provisions to 

Subpart UUUUU 

Appendix A to Subpart UUUUU—Hg 

Monitoring Provisions 

Appendix B to Subpart UUUUU—HCl and 

HF Monitoring Provisions 

Subpart UUUUU—National Emission 

Standards for Hazardous Air 

Pollutants: Coal- and Oil-Fired Electric 

Utility Steam Generating Units 

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 coal-fired EGU or an 

oil-fired EGU as defined in § 63.10042 of 

this subpart. 


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§ 63.9982 What is the affected source of 

this subpart? 

(a) This subpart applies to each 

individual or group of two or more new, 

reconstructed, and existing affected 

source(s) as described in paragraphs 

(a)(1) and (2) of this section within a 

contiguous area and under common 

control. 

(1) The affected source of this subpart 

is the collection of all existing coal- or 

oil-fired EGUs, as defined in 63.10042, 

within a subcategory. 

(2) The affected source of this subpart 

is each new or reconstructed coal- or 

oil-fired EGU as defined in 63.10042. 

(b) An EGU is new if you commence 

construction of the coal- or oil-fired 

EGU after May 3, 2011, and you meet 

the applicability criteria at the time you 

commence construction. 

(c) An EGU is reconstructed if you 

meet the reconstruction criteria as 

defined in § 63.2, you commence 

reconstruction after May 3, 2011, and 

you meet the applicability criteria at the 

time you commence reconstruction. 

(d) An EGU is existing if it is not new 

or reconstructed. An existing electric 

steam generating unit that meets the 

applicability requirements after the 

effective date of this final rule due to a 

change process (e.g., fuel or utilization) 

is considered to be an existing source 

under this subpart. 

§ 63.9983 Are any EGUs not subject to this 

subpart? 

The types of electric steam generating 

units listed in paragraphs (a) through (d) 

of this section are not subject to this 

subpart. 

(a) Any unit designated as a stationary 

combustion turbine, other than an 

integrated gasification combined cycle 

(IGCC) unit, covered by 40 CFR part 63, 

subpart YYYY. 

(b) Any electric utility steam 

generating unit that is not a coal- or oilfired EGU and combusts natural gas for 

more than 10.0 percent of the average 

annual heat input during any 3 calendar 

years or for more than 15.0 percent of 

the annual heat input during any 

calendar year. 

(c) Any electric utility steam 

generating unit that has the capability of 

combusting more than 25 MW of coal or 

oil but did not fire coal or oil for more 

than 10.0 percent of the average annual 

heat input during any 3 calendar years 

or for more than 15.0 percent of the 

annual heat input during any calendar 

year. Heat input means heat derived 

from combustion of fuel in an EGU and 

does not include the heat derived from 

preheated combustion air, recirculated 

flue gases or exhaust gases from other 

sources (such as stationary gas turbines, 

internal combustion engines, and 

industrial boilers). 

(d) Any electric steam generating unit 

combusting solid waste is a solid waste 

incineration unit subject to standards 

established under sections 129 and 111 

of the Clean Air Act. 

§ 63.9984 When do I have to comply with 

this subpart? 

(a) If you have a new or reconstructed 

EGU, you must comply with this 

subpart by April 16, 2012 or upon 

startup of your EGU, whichever is later, 

and as further provided for in 

§ 63.10005(g). 

(b) If you have an existing EGU, you 

must comply with this subpart no later 

than April 16, 2015. 

(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 April 16, 

2012 for new sources or April 16, 2015 

for existing sources must comply with 

the applicable existing source 

provisions of this subpart on the date 

such unit meets the definition of an 

EGU subject to this subpart. 

(e) If you own or operate an electric 

steam generating unit that is exempted 

from this subpart under § 63.9983(d), if 

the manner of operating the unit 

changes such that the combustion of 

waste is discontinued and the unit 

becomes a coal-fired or oil-fired EGU (as 

defined in § 63.10042), you must be in 

compliance with this subpart on April 

16, 2015 or on the effective date of the 

switch from waste combustion to coal or 

oil combustion, whichever is later. 

(f) You must demonstrate that 

compliance has been achieved, by 

conducting the required performance 

tests and other activities, no later than 

180 days after the applicable date in 

paragraph (a), (b), (c), (d), or (e) of this 

section. 

§ 63.9985 What is a new EGU? 

(a) A new EGU is an EGU that meets 

any of the criteria specified 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. 

(b) [Reserved] 

Emission Limitations and Work 

Practice Standards 

§ 63.9990 What are the subcategories of 

EGUs? 

(a) Coal-fired EGUs are subcategorized 

as defined in paragraphs (a)(1) through 

(a)(2) of this section and as defined in 

§ 63.10042. 

(1) EGUs designed for coal with a 

heating value greater than or equal to 

8,300 Btu/lb, and 

(2) EGUs designed for low rank virgin 

coal. 

(b) Oil-fired EGUs are subcategorized 

as noted in paragraphs (b)(1) through 

(b)(4) of this section and as defined in 

§ 63.10042. 

(1) Continental liquid oil-fired EGUs 

(2) Non-continental liquid oil-fired 

EGUs, 

(3) Limited-use liquid oil-fired EGUs, 

and 

(4) EGUs designed to burn solid oilderived fuel. 

(c) IGCC units combusting either 

gasified coal or gasified solid oil-derived 

fuel. For purposes of compliance, 

monitoring, recordkeeping, and 

reporting requirements in this subpart, 

IGCC units are subject in the same 

manner as coal-fired units and solid oilderived fuel-fired units, unless 

otherwise indicated. 

§ 63.9991 What emission limitations, work 

practice standards, and operating limits 

must I meet? 

(a) You must meet the requirements in 

paragraphs (a)(1) and (2) of this section. 

You must meet these requirements at all 

times. 

(1) You must meet each emission 

limit and work practice standard in 

Table 1 through 3 to this subpart that 

applies to your EGU, for each EGU at 

your source, except as provided under 

§ 63.10009. 

(2) You must meet each operating 

limit in Table 4 to this subpart that 

applies to your EGU. 

(b) As provided in § 63.6(g), the 

Administrator may approve use of an 

alternative to the work practice 

standards in this section. 

(c) You may use the alternate SO2

limit in Tables 1 and 2 to this subpart 

only if your coal-fired EGU: 

(1) Has a system using wet or dry flue 

gas desulfurization technology and SO2

continuous emissions monitoring 

system (CEMS) installed on the unit; 

and 

(2) At all times, you operate the wet 

or dry flue gas desulfurization 

technology installed on the unit 

consistent with § 63.10000(b). 


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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, liquid oil-fired, or solid oilderived fuel-fired EGUs, you are 

required to meet the work practice 

requirements in Table 3 to this subpart 

during periods of startup or shutdown. 

(b) At all times you must operate and 

maintain any affected source, including 

associated air pollution control 

equipment and monitoring equipment, 

in a manner consistent with safety and 

good air pollution control practices for 

minimizing emissions. Determination of 

whether such operation and 

maintenance procedures are being used 

will be based on information available 

to the EPA Administrator which may 

include, but is not limited to, 

monitoring results, review of operation 

and maintenance procedures, review of 

operation and maintenance records, and 

inspection of the source. 

(c)(1) For coal-fired units and solid 

oil-derived fuel-fired units, initial 

performance testing is required for all 

pollutants, to demonstrate compliance 

with the applicable emission limits. 

(i) For a coal-fired or solid oil-derived 

fuel-fired EGU or IGCC EGU, you may 

conduct the initial performance testing 

in accordance with § 63.10005(h), to 

determine whether the unit qualifies as 

a low emitting EGU (LEE) for one or 

more applicable emissions limits, with 

two exceptions: 

(A) You may not pursue the LEE 

option if your coal-fired, IGCC, or solid 

oil-derived fuel-fired EGU is equipped 

with an acid gas scrubber and has a 

main stack and bypass stack exhaust 

configuration, and 

(B) You may not pursue the LEE 

option for Hg if your coal-fired, solid 

oil-fired fuel fired EGU or IGCC EGU is 

new. 

(ii) For a qualifying LEE for Hg 

emissions limits, you must conduct a 

30-day performance test using Method 

30B at least once every 12 calendar 

months to demonstrate continued LEE 

status. 

(iii) For a qualifying LEE of any other 

applicable emissions limits, you must 

conduct a performance test at least once 

every 36 calendar months to 

demonstrate continued LEE status. 

(iv) If your coal-fired or solid oilderived fuel-fired EGU or IGCC EGU 

does not qualify as a LEE for total nonmercury HAP metals, individual nonmercury HAP metals, or filterable 

particulate matter (PM), you must 

demonstrate compliance through an 

initial performance test and you must 

monitor continuous performance 

through either use of a particulate 

matter continuous parametric 

monitoring system (PM CPMS), a PM 

CEMS, or compliance performance 

testing repeated quarterly. 

(A) 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 nonmercury HAP metals, individual nonmercury HAP metals or filterable PM. 

You will use the PM CPMS to 

demonstrate continuous compliance 

with this operating limit. If you elect to 

use a PM CPMS, you must repeat the 

performance test annually for the 

selected pollutant limit and reassess and 

adjust the site-specific operating limit in 

accordance with the results of the 

performance test. 

(B) You may also opt to install and 

operate a particulate matter CEMS 

certified in accordance with 

Performance Specification 11 and 

Procedure 2 of 40 CFR part 60, 

Appendices B and F, respectively, in 

accordance with § 63.10010(i). 

(v) If your coal-fired or solid oilderived fuel-fired EGU does not qualify 

as a LEE for hydrogen chloride (HCl), 

you may demonstrate initial and 

continuous compliance through use of 

an HCl CEMS, installed and operated in 

accordance with Appendix B to this 

subpart. As an alternative to HCl CEMS, 

you may demonstrate initial and 

continuous compliance by conducting 

an initial and periodic quarterly 

performance stack test for HCl. If your 

EGU uses wet or dry flue gas 

desulfurization technology (this 

includes limestone injection into a 

fluidized bed 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 oilderived fuel-fired EGU does not qualify 

as a LEE for Hg, you must demonstrate 

initial and continuous compliance 

through use of a Hg CEMS or a sorbent 

trap monitoring system, in accordance 

with appendix A to this subpart. 

(2) For liquid oil-fired EGUs, except 

limited use liquid 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 performance 

testing in accordance with 

§ 63.10005(h), to determine whether the 

unit qualifies as a LEE for one or more 

pollutants. For a qualifying LEE for Hg 

emissions limits, you must conduct a 

30-day performance test using Method 

30B at least once every 12 calendar 

months to demonstrate continued LEE 

status. For a qualifying LEE of any other 

applicable emissions limits, you must 

conduct a performance test at least once 

every 36 calendar months to 

demonstrate continued LEE status. 

(ii) If your existing liquid oil-fired 

unit does not qualify as a LEE for total 

HAP metals (including mercury), 

individual metals (including mercury), 

or filterable PM you must demonstrate 

compliance through an initial 

performance test and you must monitor 

continuous performance through either 

use of a PM CPMS, a PM CEMS, or 

performance testing conducted 

quarterly. 

(A) If you elect to use PM CPMS, you 

will establish a 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. 

(B) If you elect to use a PM CEMS, 

you will use the CEMS in accordance 

with § 63.10010(i) to demonstrate initial 

and continuous compliance with the 

filterable PM emission limit. 

(iii) If your existing liquid oil-fired 

unit does not qualify as a LEE for 

hydrogen chloride (HCl) or for hydrogen 

fluoride (HF), you may demonstrate 

initial and continuous compliance 

through use of an HCl CEMS, an HF 

CEMS, or an HCl and HF CEMS, 

installed and operated in accordance 

with Appendix B to this rule. As an 

alternative to HCl CEMS, HF CEMS, or 

HCl and HF CEMS, you may 

demonstrate initial and continuous 

compliance by conducting periodic 

quarterly performance stack tests for 

HCl and HF. If you elect to demonstrate 

compliance through quarterly 

performance testing, then you must also 

develop a site-specific monitoring plan 

to ensure that the operations of the unit 

remain consistent with those during the 

performance test. As another alternative, 

you may measure or obtain, and keep 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9467 

records of, fuel moisture content; as 

long as fuel moisture does not exceed 

1.0 percent by weight, you need not 

conduct other HCl or HF monitoring or 

testing. 

(iv) If your unit qualifies as a limiteduse liquid oil-fired as defined in 

§ 63.10042, then you are not subject to 

the emission limits in Tables 1 and 2, 

but must comply with the performance 

tune-up work practice requirements in 

Table 3. 

(d)(1) If you demonstrate compliance 

with any applicable emissions limit 

through use of a continuous monitoring 

system (CMS), where a CMS includes a 

continuous parameter monitoring 

system (CPMS) as well as a continuous 

emissions monitoring system (CEMS), 

you must develop a site-specific 

monitoring plan and submit this sitespecific 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 Administrator for 

alternative monitoring parameters under 

§ 63.8(f). This requirement to develop 

and submit a site-specific monitoring 

plan does not apply to affected sources 

with existing monitoring plans that 

apply to CEMS and CPMS prepared 

under Appendix B to part 60 or part 75 

of this chapter, and that meet the 

requirements of § 63.10010. Using the 

process described in § 63.8(f)(4), you 

may request approval of monitoring 

system quality assurance and quality 

control procedures alternative to those 

specified in this paragraph of this 

section and, if approved, include those 

in your site-specific 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 qualityassured either according to part 75 of 

this chapter, or appendix A or B to this 

subpart; and 

(ii) The recordkeeping and reporting 

requirements of part 75 of this chapter, 

or appendix A or B to this subpart, that 

pertain to the CMS are met. 

(3) If requested by the Administrator, 

you must submit the monitoring plan 

(or relevant portion of the plan) at least 

60 days before the initial performance 

evaluation of a particular CMS, except 

where the CMS has already undergone 

a performance evaluation that meets the 

requirements of § 63.10010 (e.g., if the 

CMS was previously certified under 

another program). 

(4) You must operate and maintain 

the CMS according to the site-specific 

monitoring plan. 

(5) The provisions of the site-specific 

monitoring plan must address the 

following items: 

(i) Installation of the CEMS or sorbent 

trap monitoring system sampling probe 

or other interface at a measurement 

location relative to each affected process 

unit such that the measurement is 

representative of control of the exhaust 

emissions (e.g., on or downstream of the 

last control device). See § 63.10010(a) 

for further details. For CPMS 

installations, follow the procedures in 

§ 63.10010(h). 

(ii) Performance and equipment 

specifications for the sample interface, 

the pollutant concentration or 

parametric signal analyzer, and the data 

collection and reduction systems. 

(iii) Schedule for conducting initial 

and periodic performance evaluations. 

(iv) Performance evaluation 

procedures and acceptance criteria (e.g., 

calibrations), including ongoing data 

quality assurance procedures in 

accordance with the general 

requirements of § 63.8(d). 

(v) On-going operation and 

maintenance procedures, in accordance 

with the general requirements of 

§§ 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii). 

(vi) Conditions that define a CMS that 

is out of control consistent with 

§ 63.8(c)(7)(i) and for responding to out 

of control periods consistent with 

§§ 63.8(c)(7)(ii) and (c)(8). 

(vii) On-going recordkeeping and 

reporting procedures, in accordance 

with the general requirements of 

§§ 63.10(c), (e)(1), and (e)(2)(i), or as 

specifically required under this subpart. 

(e) As part of your demonstration of 

continuous compliance, you must 

perform periodic tune-ups of your 

EGU(s), according to § 63.10021(e). 

(f) You are subject to the requirements 

of this subpart for at least 6 months 

following the last date you met the 

definition of an EGU subject to this 

subpart (e.g., 6 months after a 

cogeneration unit provided more than 

one third of its potential electrical 

output capacity and more than 25 

megawatts electrical output to any 

power distributions system for sale). 

You may opt to remain subject to the 

provisions of this subpart beyond 6 

months after the last date you met the 

definition of an EGU subject to this 

subpart, unless you are a solid waste 

incineration unit subject to standards 

under CAA section 129 (e.g., 40 CFR 

part 60, subpart CCCC (New Source 

Performance Standards (NSPS) for 

Commercial and Industrial Solid Waste 

Incineration Units, or Subpart DDDD 

(Emissions Guidelines (EG) for Existing 

Commercial and Industrial Solid Waste 

Incineration Units). Notwithstanding 

the provisions of this subpart, an EGU 

that starts combusting solid waste is 

immediately subject to standards under 

CAA section 129 and the EGU remains 

subject to those standards until the EGU 

no longer meets the definition of a solid 

waste incineration unit consistent with 

the provisions of the applicable CAA 

section 129 standards. 

(g) If you no longer meet the 

definition of an EGU subject to this 

subpart you must be in compliance with 

any newly applicable standards on the 

date you are no longer subject to this 

subpart. The date you are no longer 

subject to this subpart is a date selected 

by you, that must be at least 6 months 

from the date that you last met the 

definition of an EGU subject to this 

subpart or the date you begin 

combusting solid waste, consistent with 

§ 63.9983(d). Your source must remain 

in compliance with this subpart until 

the date you select to cease complying 

with this subpart or the date you begin 

combusting solid waste, whichever is 

earlier. 

(h)(1) If you own or operate an EGU 

that does not meet the definition of an 

EGU subject to this subpart on April 16, 

2015, and you commence or 

recommence operations that cause you 

to meet the definition of an EGU subject 

to this subpart, you are subject to the 

provisions of this subpart, including, 

but not limited to, the emission 

limitations and the monitoring 

requirements, as of the first day you 

meet the definition of an EGU subject to 

this subpart. You must complete all 

initial compliance demonstrations for 

this subpart applicable to your EGU 

within 180 days after you commence or 

recommence operations that cause you 

to meet the definition of an EGU subject 

to this subpart. 

(2) You must provide 30 days prior 

notice of the date you intend to 

commence or recommence operations 

that cause you to meet the definition of 

an EGU subject to this subpart. The 

notification must identify: 

(i) The name of the owner or operator 

of the EGU, the location of the facility, 

the unit(s) that will commence or 

recommence operations that will cause 

the unit(s) to meet the definition of an 

EGU subject to this subpart, and the 

date of the notice; 

(ii) The 40 CFR part 60, part 62, or 

part 63 subpart and subcategory 


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9468 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

currently applicable to your unit(s), and 

the subcategory of this subpart that will 

be applicable after you commence or 

recommence operation that will cause 

the unit(s) to meet the definition of an 

EGU subject to this subpart; 

(iii) The date on which you became 

subject to the currently applicable 

emission limits; 

(iv) The date upon which you will 

commence or recommence operations 

that will cause your unit to meet the 

definition of an EGU subject to this 

subpart, consistent with paragraph (f) of 

this section. 

(i)(1) If you own or operate an EGU 

subject to this subpart, and it has been 

at least 6 months since you operated in 

a manner that caused you to meet the 

definition of an EGU subject to this 

subpart, you may, consistent with 

paragraph (g) of this section, select the 

date on which your EGU will no longer 

be subject to this subpart. You must be 

in compliance with any newly 

applicable section 112 or 129 standards 

on the date you selected. 

(2) You must provide 30 days prior 

notice of the date your EGU will cease 

complying with this subpart. The 

notification must identify: 

(i) The name of the owner or operator 

of the EGU(s), the location of the 

facility, the EGU(s) that will cease 

complying with this subpart, and the 

date of the notice; 

(ii) The currently applicable 

subcategory under this subpart, and any 

40 CFR part 60, part 62, or part 63 

subpart and subcategory that will be 

applicable after you cease complying 

with this subpart; 

(iii) The date on which you became 

subject to this subpart; 

(iv) The date upon which you will 

cease complying with this subpart, 

consistent with paragraph (g) of this 

section. 

(j) All air pollution control equipment 

necessary for compliance with any 

newly applicable emissions limits 

which apply as a result of the cessation 

or commencement or recommencement 

of operations that cause your EGU to 

meet the definition of an EGU subject to 

this subpart must be installed and 

operational as of the date your source 

ceases to be or becomes subject to this 

subpart. 

(k) All monitoring systems necessary 

for compliance with any newly 

applicable monitoring requirements 

which apply as a result of the cessation 

or commencement or recommencement 

of operations that cause your EGU to 

meet the definition of an EGU subject to 

this subpart must be installed and 

operational as of the date your source 

ceases to be or becomes subject to this 

subpart. All calibration and drift checks 

must be performed as of the date your 

source ceases to be or becomes subject 

to this subpart. You must also comply 

with provisions of §§ 63.10010, 

63.10020, and 63.10021 of this subpart. 

Relative accuracy tests must be 

performed as of the performance test 

deadline for PM CEMS, if applicable. 

Relative accuracy testing for other 

CEMS need not be repeated if that 

testing was previously performed 

consistent with CAA section 112 

monitoring requirements or monitoring 

requirements under this subpart. 

§ 63.10001 Affirmative defense for 

exceedence of emission limit during 

malfunction. 

In response to an action to enforce the 

standards set forth in § 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 

(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 of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the excess emissions resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of excess emissions that were 

the result of the malfunction. 

(b) Notification. The owner or 

operator of the affected source 

experiencing an exceedance of its 

emission limit(s) during a malfunction 

shall notify the Administrator by 

telephone or facsimile (FAX) 

transmission as soon as possible, but no 

later than two business days after the 

initial occurrence of the malfunction or, 

if it is not possible to determine within 

two business days whether the 

malfunction caused or contributed to an 

exceedance, no later than two business 

days after the owner or operator knew 

or should have known that the 

malfunction caused or contributed to an 

exceedance, but, in no event later than 

two business days after the end of the 

averaging period, if it wishes to avail 

itself of an affirmative defense to civil 

penalties for that malfunction. The 

owner or operator seeking to assert an 

affirmative defense shall also submit a 

written report to the Administrator 

within 45 days of the initial occurrence 

of the exceedance of the standard in 

§ 63.9991 to demonstrate, with all 

necessary supporting documentation, 

that it has met the requirements set forth 

in paragraph (a) of this section. The 

owner or operator may seek an 

extension of this deadline for up to 30 

additional days by submitting a written 

request to the Administrator before the 

expiration of the 45 day period. Until a 

request for an extension has been 

approved by the Administrator, the 

owner or operator is subject to the 

requirement to submit such report 


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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 inputbased limit in lb/MMBtu and an 

electrical output-based limit in lb/ 

MWh), you may demonstrate 

compliance with either emission limit. 

For a particular compliance 

demonstration, you may be required to 

conduct one or more of the following 

activities in conjunction with 

performance testing: collection of 

hourly electrical load data (megawatts); 

establishment of operating limits 

according to § 63.10011 and Tables 4 

and 7 to this subpart; and CMS 

performance evaluations. In all cases, 

you must demonstrate initial 

compliance no later than the applicable 

date in paragraph (f) of this section for 

tune-up work practices for existing 

EGUs, in § 63.9984 for other 

requirements for existing EGUs, and in 

paragraph (g) of this section for all 

requirements for new EGUs. 

(1) To demonstrate initial compliance 

with an applicable emissions limit in 

Table 1 or 2 to this subpart using stack 

testing, the initial performance test 

generally consists of three runs at 

specified process operating conditions 

using approved methods. If you are 

required to establish operating limits 

(see paragraph (d) of this section and 

Table 4 to this subpart), you must 

collect all applicable parametric data 

during the performance test period. 

Also, if you choose to comply with an 

electrical output-based emission limit, 

you must collect hourly electrical load 

data during the test period. 

(2) To demonstrate initial compliance 

using either a CMS that measures HAP 

concentrations directly (i.e., an Hg, HCl, 

or HF CEMS, or a sorbent trap 

monitoring system) or an SO2 or PM 

CEMS, the initial performance test 

consists of 30 boiler operating days of 

data collected by the initial compliance 

demonstration date specified in 

§ 63.10005 with the certified monitoring 

system. 

(i) The 30-boiler operating day CMS 

performance test must demonstrate 

compliance with the applicable Hg, HCl, 

HF, PM, or SO2 emissions limit in Table 

1 or 2 to this subpart. 

(ii) If you choose to comply with an 

electrical output-based emission limit, 

you must collect hourly electrical load 

data during the performance test period. 

(b) Performance testing requirements. 

If you choose to use performance testing 

to demonstrate initial compliance with 

the applicable emissions limits in 

Tables 1 and 2 to this subpart for your 

EGUs, you must conduct the tests 

according to § 63.10007 and Table 5 to 

this subpart. For the purposes of the 

initial compliance demonstration, you 

may use test data and results from a 

performance test conducted prior to the 

date on which compliance is required 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 calendar months prior 

to the date on which compliance is 

required as specified in § 63.9984; 

(2) For a performance test based on 

data from a certified CEMS or sorbent 

trap monitoring system, the test consists 

of all valid data CMS data recorded in 

the 30 boiler operating days 

immediately preceding that date; 

(3) The performance test was 

conducted in accordance with all 

applicable requirements in § 63.10007 

and Table 5 to this subpart; 

(4) A record of all parameters needed 

to convert pollutant concentrations to 

units of the emission standard (e.g., 

stack flow rate, diluent gas 

concentrations, hourly electrical loads) 

is available for the entire performance 

test period; and 

(5) For each performance test based 

on stack test data, you certify, and keep 

documentation demonstrating, that the 

EGU configuration, control devices, and 

fuel(s) have remained consistent with 

conditions since the prior performance 

test was conducted. 

(c) Operating limits. In accordance 

with § 63.10010 and Table 4 to this 

subpart, you may be required to 

establish operating limits using PM 

CPMS and using site-specific 

monitoring for certain liquid oil-fired 

units as part of your initial compliance 

demonstration. 

(d) CMS requirements. If, for a 

particular emission or operating limit, 

you are required to (or elect to) 

demonstrate initial compliance using a 

continuous monitoring system, the CMS 

must pass a performance evaluation 

prior to the initial compliance 

demonstration. If a CMS has been 

previously certified under another state 

or federal program and is continuing to 

meet the on-going quality-assurance 

(QA) requirements of that program, 

then, provided that the certification and 

QA provisions of that program meet the 

applicable requirements of 

§§ 63.10010(b) through (h), an 

additional performance evaluation of 

the CMS is not required under this 

subpart. 

(1) For an affected coal-fired, solid oilderived fuel-fired, or liquid oil-fired 

EGU, you may demonstrate initial 

compliance with the applicable SO2, 

HCl, or HF emissions limit in Table 1 

or 2 of this subpart through use of an 

SO2, HCl, or HF CEMS installed and 

operated in accordance with part 75 of 

this chapter or Appendix B to this 

subpart, as applicable. You may also 

demonstrate compliance with a 

filterable PM emission limit in Table 1 

or 2 of this subpart through use of a PM 

CEMS installed, certified, and operated 

in accordance with § 63.10010(i). Initial 

compliance is achieved if the arithmetic 

average of 30-boiler operating days of 

quality-assured CEMS data, expressed 

in units of the standard (see 

§ 63.10007(e)), meets the applicable 

SO2, PM, HCl, or HF emissions limit in 

Table 1 or 2 to this subpart. Use 

Equation 19–19 of Method 19 in 

appendix A–7 to part 60 of this chapter 

to calculate the 30-boiler operating day 

average emissions rate. (Note: for this 

calculation, the term Ehj in Equation 19– 

19 must be in the same units of measure 

as the applicable HCl or HF emission 

limit in Table 1 or 2 to this subpart). 

(2) For affected coal-fired or solid oilderived fuel-fired EGUs that 

demonstrate compliance with the 

applicable emission limits for total nonmercury HAP metals, individual nonmercury HAP metals, total HAP metals, 

individual HAP metals, or filterable PM 

listed in Table 1 or 2 to this subpart 

using initial performance testing and 

continuous monitoring with PM CPMS: 

(i) You must demonstrate initial 

compliance no later than the applicable 

date specified in § 63.9984(f) for existing 

EGUs and in paragraph (g) of this 

section for new EGUs. 

(ii) You must demonstrate continuous 

compliance with the PM CPMS sitespecific 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 the 

performance test. 

(3) For affected EGUs that are either 

required to or elect to demonstrate 

initial compliance with the applicable 

Hg emission limit in Table 1 or 2 of this 


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subpart using Hg CEMS or sorbent trap 

monitoring systems, initial compliance 

must be demonstrated no later than the 

applicable date specified in § 63.9984(f) 

for existing EGUs and in paragraph (g) 

of this section for new EGUs. Initial 

compliance is achieved if the arithmetic 

average of 30-boiler operating days of 

quality-assured CEMS (or sorbent trap 

monitoring system) data, expressed in 

units of the standard (see section 6.2 of 

appendix A to this subpart), meets the 

applicable Hg emission limit in Table 1 

or 2 to this subpart. 

(4) For affected liquid oil-fired EGUs 

that demonstrate compliance with the 

applicable emission limits for HCl or HF 

listed in Table 1 or 2 to this subpart 

using quarterly testing and continuous 

monitoring with a CMS: 

(i) You must demonstrate initial 

compliance no later than the applicable 

date specified in § 63.9984 for existing 

EGUs and in paragraph (g) of this 

section for new EGUs. 

(ii) You must demonstrate continuous 

compliance with the CMS site-specific 

operating limit that corresponding to the 

results of the performance test 

demonstrating compliance with the HCl 

or HF emissions limit. 

(iii) You must repeat the performance 

test annually for the HCl or HF 

emissions limit and reassess and adjust 

the site-specific operating limit in 

accordance with the results of the 

performance test. 

(e) Tune-ups. All affected EGUs are 

subject to the work practice standards in 

Table 3 of this subpart. As part of your 

initial compliance demonstration, you 

must conduct a performance tune-up of 

your EGU according to § 63.10021(e). 

(f) For existing affected sources a 

tune-up may occur prior to April 16, 

2012, so that existing sources without 

neural networks have up to 42 calendar 

months (3 years from promulgation plus 

180 days) or, in the case of units 

employing neural network combustion 

controls, up to 54 calendar months (48 

months from promulgation plus 180 

days) after the date that is specified for 

your source in § 63.9984 and according 

to the applicable provisions in 

§ 63.7(a)(2) as cited in Table 9 to this 

subpart to demonstrate compliance with 

this requirement. If a tune-up occurs 

prior to such date, the source must 

maintain adequate records to show that 

the tune-up met the requirements of this 

standard. 

(g) If your new or reconstructed 

affected source commenced 

construction or reconstruction between 

May 3, 2011, and July 2, 2011, you must 

demonstrate initial compliance with 

either the proposed emission limits or 

the promulgated emission limits no later 

than 180 days after April 16, 2012 or 

within 180 days after startup of the 

source, whichever is later, according to 

§ 63.7(a)(2)(ix). 

(1) For the new or reconstructed 

affected source described in this 

paragraph (g), if you choose to comply 

with the proposed emission limits when 

demonstrating initial compliance, you 

must conduct a second compliance 

demonstration for the promulgated 

emission limits within 3 years after 

April 16, 2012 or within 3 years after 

startup of the affected source, whichever 

is later. 

(2) If your new or reconstructed 

affected source commences construction 

or reconstruction after April 16, 2012, 

you must demonstrate initial 

compliance with the promulgated 

emission limits no later than 180 days 

after startup of the source. 

(h) Low emitting EGUs. The 

provisions of this paragraph (h) apply to 

pollutants with emissions limits from 

new EGUs except Hg and to all 

pollutants with emissions limits from 

existing EGUs. You may not pursue this 

compliance option if your existing EGU 

is equipped with an acid gas scrubber 

and has a main stack and bypass stack 

exhaust configuration. 

(1) An EGU may qualify for low 

emitting EGU (LEE) status for Hg, HCl, 

HF, filterable PM, total non-Hg HAP 

metals, or individual non-Hg HAP 

metals (or total HAP metals or 

individual HAP metals, for liquid oilfired EGUs) if you collect performance 

test data that meet the requirements of 

this paragraph (h), and if those data 

demonstrate: 

(i) For all pollutants except Hg, 

performance test emissions results less 

than 50 percent of the applicable 

emissions limits in Table 1 or 2 to this 

subpart for all required testing for 3 

consecutive years; or 

(ii) For Hg emissions from an existing 

EGU, either: 

(A) Average emissions less than 10 

percent of the applicable Hg emissions 

limit in Table 2 to this subpart 

(expressed either in units of lb/TBtu or 

lb/GWh); or 

(B) Potential Hg mass emissions of 

29.0 or fewer pounds per year and 

compliance with the applicable Hg 

emission limit in Table 2 to this subpart 

(expressed either in units of lb/TBtu or 

lb/GWh). 

(2) For all pollutants except Hg, you 

must conduct all required performance 

tests described in § 63.10007 to 

demonstrate that a unit qualifies for LEE 

status. 

(i) When conducting emissions testing 

to demonstrate LEE status, you must 

increase the minimum sample volume 

specified in Table 1 or 2 nominally by 

a factor of two. 

(ii) Follow the instructions in 

§ 63.10007(e) and Table 5 to this subpart 

to convert the test data to the units of 

the applicable standard. 

(3) For Hg, you must conduct a 30- 

boiler operating day performance test 

using Method 30B in appendix A–8 to 

part 60 of this chapter to determine 

whether a unit qualifies for LEE status. 

Locate the Method 30B sampling probe 

tip at a point within the 10 percent 

centroidal area of the duct at a location 

that meets Method 1 in appendix A–1 

to part 60 of this chapter and conduct 

at least three nominally equal length test 

runs over the 30-boiler operating day 

test period. Collect Hg emissions data 

continuously over the entire test period 

(except when changing sorbent traps or 

performing required reference method 

QA procedures), under all process 

operating conditions. You may use a 

pair of sorbent traps to sample the stack 

gas for no more than 10 days. 

(i) Depending on whether you intend 

to assess LEE status for Hg in terms of 

the lb/TBtu or lb/GWh emission limit in 

Table 2 to this subpart or in terms of the 

annual Hg mass emissions limit of 29.0 

lb/year, you will have to collect some or 

all of the following data during the 30- 

boiler operating day test period (see 

paragraph (h)(3)(iii) of this section): 

(A) Diluent gas (CO2 or O2) data, using 

either Method 3A in appendix A–3 to 

part 60 of this chapter or a diluent gas 

monitor that has been certified 

according to part 75 of this chapter. 

(B) Stack gas flow rate data, using 

either Method 2, 2F, or 2G in 

appendices A–1 and A–2 to part 60 of 

this chapter, or a flow rate monitor that 

has been certified according to part 75 

of this chapter. 

(C) Stack gas moisture content data, 

using either Method 4 in appendix A– 

1 to part 60 of this chapter, or a 

moisture monitoring system that has 

been certified according to part 75 of 

this chapter. Alternatively, an 

appropriate fuel-specific default 

moisture value from § 75.11(b) of this 

chapter may be used in the calculations 

or you may petition the Administrator 

under § 75.66 of this chapter for use of 

a default moisture value for non-coalfired 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-boiler operating day test period. If 

you opt to use EPA reference methods 

rather than CEMS for any parameter, 

you must perform at least one 


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representative test run on each 

operating day of the test period, using 

the applicable reference method. 

(iii) Calculate the average Hg 

concentration, in mg/m3 (dry basis), for 

the 30-boiler operating day performance 

test, as the arithmetic average of all 

Method 30B sorbent trap results. Also 

calculate, as applicable, the average 

values of CO2 or O2 concentration, stack 

gas flow rate, stack gas moisture 

content, and electrical load for the test 

period. Then: 

(A) To express the test results in units 

of lb/TBtu, follow the procedures in 

§ 63.10007(e). Use the average Hg 

concentration and diluent gas values in 

the calculations. 

(B) To express the test results in units 

of lb/GWh, use Equations A–3 and A– 

4 in section 6.2.2 of appendix A to this 

subpart, replacing the hourly values 

‘‘Ch’’, ‘‘Qh’’, ‘‘Bws’’ and ‘‘(MW)h’’ with the 

average values of these parameters from 

the performance test. 

(C) To calculate pounds of Hg per 

year, use one of the following methods: 

(1) Multiply the average lb/TBtu Hg 

emission rate (determined according to 

paragraph (h)(3)(iii)(A) of this section) 

by the maximum potential annual heat 

input to the unit (TBtu), which is equal 

to the maximum rated unit heat input 

(TBtu/hr) times 8,760 hours. If the 

maximum rated heat input value is 

expressed in units of MMBtu/hr, 

multiply it by 106 to convert it to TBtu/ 

hr; or 

(2) Multiply the average lb/GWh Hg 

emission rate (determined according to 

paragraph (h)(3)(iii)(B) of this section) 

by the maximum potential annual 

electricity generation (GWh), which is 

equal to the maximum rated electrical 

output of the unit (GW) times 8,760 

hours. If the maximum rated electrical 

output value is expressed in units of 

MW, multiply it by 103 to convert it to 

GW; or 

(3) If an EGU has a federallyenforceable permit limit on either the 

annual heat input or the number of 

annual operating hours, you may 

modify the calculations in paragraph 

(h)(3)(iii)(C)(1) of this section by 

replacing the maximum potential 

annual heat input or 8,760 unit 

operating hours with the permit limit on 

annual heat input or operating hours (as 

applicable). 

(4) For a group of affected units that 

vent to a common stack, you may either 

assess LEE status for the units 

individually by performing a separate 

emission test of each unit in the duct 

leading from the unit to the common 

stack, or you may perform a single 

emission test in the common stack. If 

you choose the common stack testing 

option, the units in the configuration 

qualify for LEE status if: 

(i) The emission rate measured at the 

common stack is less than 50 percent 

(10 percent for Hg) of the applicable 

emission limit in Table 1 or 2 to this 

subpart; or 

(ii) For Hg from an existing EGU, the 

applicable Hg emission limit in Table 2 

to this subpart is met and the potential 

annual mass emissions, calculated 

according to paragraph (h)(3)(iii) of this 

section (with some modifications), are 

less than or equal to 29.0 pounds times 

the number of units sharing the 

common stack. Base your calculations 

on the combined heat input capacity of 

all units sharing the stack (i.e., either 

the combined maximum rated value or, 

if applicable, a lower combined value 

restricted by permit conditions or 

operating hours). 

(5) For an affected unit with a 

multiple stack or duct configuration in 

which the exhaust stacks or ducts are 

downstream of all emission control 

devices, you must perform a separate 

emission test in each stack or duct. The 

unit qualifies for LEE status if: 

(i) The emission rate, based on all test 

runs performed at all of the stacks or 

ducts, is less than 50 percent (10 

percent for Hg) of the applicable 

emission limit in Table 1 or 2 to this 

subpart; or 

(ii) For Hg from an existing EGU, the 

applicable Hg emission limit in Table 2 

to this subpart is met and the potential 

annual mass emissions, calculated 

according to paragraph (h)(3)(iii) of this 

section, are less than or equal to 29.0 

pounds. Use the average Hg emission 

rate from paragraph (h)(5)(i) of this 

section in your calculations. 

(i) Liquid-oil fuel moisture 

measurement. If your EGU combusts 

liquid fuels, if your fuel moisture 

content is no greater than 1.0 percent by 

weight, and if you would like to 

demonstrate initial and ongoing 

compliance with HCl and HF emissions 

limits, you must meet the requirements 

of paragraphs (i)(1) through (5) of this 

section. 

(1) Measure fuel moisture content of 

each shipment of fuel if your fuel 

arrives on a batch basis; or 

(2) Measure fuel moisture content 

daily if your fuel arrives on a 

continuous basis; or 

(3) Obtain and maintain a fuel 

moisture certification from your fuel 

supplier. 

(4) Use one of the following methods 

to determine fuel moisture content: 

(i) ASTM D95–05 (Reapproved 2010), 

‘‘Standard Test Method for Water in 

Petroleum Products and Bituminous 

Materials by Distillation,’’ or 

(ii) ASTM D4006–11, ‘‘Standard Test 

Method for Water in Crude Oil by 

Distillation,’’ including Annex A1 and 

Appendix A1, or 

(iii) ASTM D4177–95 (Reapproved 

2010), ‘‘Standard Practice for Automatic 

Sampling of Petroleum and Petroleum 

Products,’’ including Annexes A1 

through A6 and Appendices X1 and X2, 

or 

(iv) ASTM D4057–06 (Reapproved 

2011), ‘‘Standard Practice for Manual 

Sampling of Petroleum and Petroleum 

Products,’’ including Annex A1. 

(5) Should the moisture in your liquid 

fuel be more than 1.0 percent by weight, 

you must 

(i) Conduct HCl and HF emissions 

testing quarterly (and monitor sitespecific operating parameters as 

provided in § 63.10000(c)(2)(iii) or 

(ii) Use an HCl CEMS and/or HF 

CEMS. 

(j) Startup and shutdown for coalfired or solid oil derived-fired units. 

You must follow the requirements given 

in Table 3 to this subpart. 

(k) You must submit a Notification of 

Compliance Status summarizing the 

results of your initial compliance 

demonstration, as provided in 

§ 63.10030. 

§ 63.10006 When must I conduct 

subsequent performance tests or tune-ups? 

(a) For liquid oil-fired, solid oilderived fuel- and coal-fired EGUs and 

IGCC units using PM CPMS to monitor 

continuous performance with an 

applicable emission limit as provided 

for under § 63.10000(c), you must 

conduct all applicable performance tests 

according to Table 5 to this subpart and 

§ 63.10007 at least every year. 

(b) For affected units meeting the LEE 

requirements of § 63.10005(h), you must 

repeat the performance test once every 

3 years (once every year for Hg) 

according to Table 5 and § 63.10007. 

Should subsequent emissions testing 

results show the unit does not meet the 

LEE eligibility requirements, LEE status 

is lost. If this should occur: 

(1) For all pollutant emission limits 

except for Hg, you must conduct 

emissions testing quarterly, except as 

otherwise provided in § 63.10021(d)(1). 

(2) For Hg, you must install, certify, 

maintain, and operate a Hg CEMS or a 

sorbent trap monitoring system in 

accordance with appendix A to this 

subpart, within 6 calendar months of 

losing LEE eligibility. Until the Hg 

CEMS or sorbent trap monitoring system 

is installed, certified, and operating, you 

must conduct Hg emissions testing 

quarterly, except as otherwise provided 

in § 63.10021(d)(1). You must have 3 

calendar years of testing and CEMS or 


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sorbent trap monitoring system data that 

satisfy the LEE emissions criteria to 

reestablish LEE status. 

(c) Except where paragraphs (a) or (b) 

of this section apply, or where you 

install, certify, and operate a PM CEMS 

to demonstrate compliance with a 

filterable PM emission limit, for liquid 

oil-fired EGUs, you must conduct all 

applicable periodic emissions tests for 

filterable PM, or individual or total HAP 

metals emissions according to Table 5 to 

this subpart and § 63.10007 at least 

quarterly, except as otherwise provided 

in § 63.10021(d)(1). 

(d) Except where paragraph (b) of this 

section applies, for solid oil-derived 

fuel- and coal-fired EGUs that do not 

use either an HCl CEMS to monitor 

compliance with the HCl limit or an SO2

CEMS to monitor compliance with the 

alternate equivalent SO2 emission limit, 

you must conduct all applicable 

periodic HCl emissions tests according 

to Table 5 to this subpart and § 63.10007 

at least quarterly, except as otherwise 

provided in § 63.10021(d)(1). 

(e) Except where paragraph (b) of this 

section applies, for liquid oil-fired EGUs 

without HCl CEMS, HF CEMS, or HCl 

and HF CEMS, you must conduct all 

applicable emissions tests for HCl, HF, 

or HCl and HF emissions according to 

Table 5 to this subpart and § 63.10007 

at least quarterly, except as otherwise 

provided in § 63.10021(d)(1), and 

conduct site-specific monitoring under a 

plan as provided for in 

§ 63.10000(c)(2)(iii). 

(f) Unless you follow the requirements 

listed in paragraphs (g) and (h) of this 

section, performance tests required at 

least every 3 calendar years must be 

completed within 35 to 37 calendar 

months after the previous performance 

test; performance tests required at least 

every year must be completed within 11 

to 13 calendar months after the previous 

performance test; and performance tests 

required at least quarterly must be 

completed within 80 to 100 calendar 

days after the previous performance test, 

except as otherwise provided in 

§ 63.10021(d)(1). 

(g) If you elect to demonstrate 

compliance using emissions averaging 

under § 63.10009, you must continue to 

conduct performance stack tests at the 

appropriate frequency given in section 

(c) through (f) of this section. 

(h) If a performance test on a nonmercury LEE shows emissions in excess 

of 50 percent of the emission limit and 

if you choose to reapply for LEE status, 

you must conduct performance tests at 

the appropriate frequency given in 

section (c) through (e) of this section for 

that pollutant until all performance tests 

over a consecutive 3-year period show 

compliance with the LEE criteria. 

(i) If you are required to meet an 

applicable tune-up work practice 

standard, you must conduct a 

performance tune-up according to 

§ 63.10021(e). 

(1) For EGUs not employing neural 

network combustion optimization 

during normal operation, each 

performance tune-up specified in 

§ 63.10021(e) must be no more than 36 

calendar months after the previous 

performance tune-up. 

(2) For EGUs employing neural 

network combustion optimization 

systems during normal operation, each 

performance tune-up specified in 

§ 63.10021(e) must be no more than 48 

calendar months after the previous 

performance tune-up. 

(j) You must report the results of 

performance tests and performance 

tune-ups within 60 days after the 

completion of the performance tests and 

performance tune-ups. The reports for 

all subsequent performance tests must 

include all applicable information 

required in § 63.10031. 

§ 63.10007 What methods and other 

procedures must I use for the performance 

tests? 

(a) Except as otherwise provided in 

this section, you must conduct all 

required performance tests according to 

§ 63.7(d), (e), (f), and (h). You must also 

develop a site-specific test plan 

according to the requirements in 

§ 63.7(c). 

(1) If you use CEMS (Hg, HCl, SO2, or 

other) to determine compliance with a 

30-boiler operating day rolling average 

emission limit, you must collect data for 

all nonexempt unit operating conditions 

(see § 63.10011(g) and Table 3 to this 

subpart). 

(2) If you conduct performance testing 

with test methods in lieu of continuous 

monitoring, operate the unit at 

maximum normal operating load 

conditions during each periodic (e.g., 

quarterly) performance test. Maximum 

normal operating load will be generally 

between 90 and 110 percent of design 

capacity but should be representative of 

site specific normal operations during 

each test run. 

(3) For establishing operating limits 

with particulate matter continuous 

parametric monitoring system (PM 

CPMS) to demonstrate compliance with 

a PM or non Hg metals emissions limit, 

operate the unit at maximum normal 

operating load conditions during the 

performance test period. Maximum 

normal operating load will be generally 

between 90 and 110 percent of design 

capacity but should be representative of 

site specific normal operations during 

each test run. 

(b) You must conduct each 

performance test (including traditional 

3-run stack tests, 30-boiler operating day 

tests based on CEMS data (or sorbent 

trap monitoring system data), and 30- 

boiler operating day Hg emission tests 

for LEE qualification) according to the 

requirements in Table 5 to this subpart. 

(c) If you choose to comply with the 

filterable PM emission limit and 

demonstrate continuous performance 

using a PM CPMS for an applicable 

emission limit as provided for in 

§ 63.10000(c), you must also establish 

an operating limit according to 

§ 63.10011(b)(5) and Tables 4 and 6 to 

this subpart. Should you desire to have 

operating limits that correspond to loads 

other than maximum normal operating 

load, you must conduct testing at those 

other loads to determine the additional 

operating limits. 

(d) Except for a 30-boiler operating 

day performance test based on CEMS (or 

sorbent trap monitoring system) data, 

where the concept of test runs does not 

apply, you must conduct a minimum of 

three separate test runs for each 

performance test, as specified in 

§ 63.7(e)(3). Each test run must comply 

with the minimum applicable sampling 

time or volume specified in Table 1 or 

2 to this subpart. Sections 63.10005(d) 

and (h), respectively, provide special 

instructions for conducting performance 

tests based on CEMS or sorbent trap 

monitoring systems, and for conducting 

emission tests for LEE qualification. 

(e) To use the results of performance 

testing to determine compliance with 

the applicable emission limits in Table 

1 or 2 to this subpart, proceed as 

follows: 

(1) Except for a 30-boiler operating 

day performance test based on CEMS (or 

sorbent trap monitoring system) data, if 

measurement results for any pollutant 

are reported as below the method 

detection level (e.g., laboratory 

analytical results for one or more 

sample components are below the 

method defined analytical detection 

level), you must use the method 

detection level as the measured 

emissions level for that pollutant in 

calculating compliance. The measured 

result for a multiple component analysis 

(e.g., analytical values for multiple 

Method 29 fractions both for individual 

HAP metals and for total HAP metals) 

may include a combination of method 

detection level data and analytical data 

reported above the method detection 

level. 

(2) If the limits are expressed in lb/ 

MMBtu or lb/TBtu, you must use the Ffactor methodology and equations in 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9473 

sections 12.2 and 12.3 of EPA Method 

19 in appendix A–7 to part 60 of this 

chapter. In cases where an appropriate 

F-factor is not listed in Table 19–2 of 

Method 19, you may use F-factors from 

Table 1 in section 3.3.5 of appendix F 

to part 75 of this chapter, or F-factors 

derived using the procedures in section 

3.3.6 of appendix to part 75 of this 

chapter. Use the following factors to 

convert the pollutant concentrations 

measured during the initial performance 

tests to units of lb/scf, for use in the 

applicable Method 19 equations: 

(i) Multiply SO2 ppm by 1.66 × 10¥7; 

(ii) Multiply HCl ppm by 9.43 × 10¥8; 

(iii) Multiply HF ppm by 5.18 × 10¥8; 

(iv) Multiply HAP metals 

concentrations (mg/dscm) by 6.24 × 

10¥8; and 

(v) Multiply Hg concentrations (mg/ 

scm) by 6.24 × 10¥11. 

(3) To determine compliance with 

emission limits expressed in lb/MWh or 

lb/GWh, you must first calculate the 

pollutant mass emission rate during the 

performance test, in units of lb/h. For 

Hg, if a CEMS or sorbent trap 

monitoring system is used, use Equation 

A–2 or A–3 in appendix A to this 

subpart (as applicable). In all other 

cases, use an equation that has the 

general form of Equation A–2 or A–3, 

replacing the value of K with 1.66 × 

10¥7 lb/scf-ppm for SO2, 9.43 × 10¥8 lb/ 

scf-ppm for HCl (if an HCl CEMS is 

used), 5.18 × 10¥8 lb/scf-ppm for HF (if 

an HF CEMS is used), or 6.24 × 10¥8 lbscm/mg-scf for HAP metals and for HCl 

and HF (when performance stack testing 

is used), and defining Ch as the average 

SO2, HCl, or HF concentration in ppm, 

or the average HAP metals 

concentration in mg/dscm. This 

calculation requires stack gas 

volumetric flow rate (scfh) and (in some 

cases) moisture content data (see 

§§ 63.10005(h)(3) and 63.10010). Then, 

if the applicable emission limit is in 

units of lb/GWh, use Equation A–4 in 

appendix A to this subpart to calculate 

the pollutant emission rate in lb/GWh. 

In this calculation, define (M)h as the 

calculated pollutant mass emission rate 

for the performance test (lb/h), and 

define (MW)h as the average electrical 

load during the performance test 

(megawatts). If the applicable emission 

limit is in lb/MWh rather than lb/GWh, 

omit the 103 term from Equation A–4 to 

determine the pollutant emission rate in 

lb/MWh. 

(f) Upon request, you shall make 

available to the EPA Administrator such 

records as may be necessary to 

determine whether the performance 

tests have been done according to the 

requirements of this section. 

§ 63.10008 [Reserved] 

§ 63.10009 May I use emissions averaging 

to comply with this subpart? 

(a) General eligibility. (1) You may use 

emissions averaging as described in 

paragraph (a)(2) of this section as an 

alternative to meeting the requirements 

of § 63.9991 for filterable PM, SO2, HF, 

HCl, non-Hg HAP metals, or Hg on an 

EGU-specific basis if: 

(i) You have more than one existing 

EGU in the same subcategory located at 

one or more contiguous properties, 

belonging to a single major industrial 

grouping, which are under common 

control of the same person (or persons 

under common control); and 

(ii) You use CEMS (or sorbent trap 

monitoring systems for determining Hg 

emissions) or quarterly emissions 

testing for demonstrating compliance. 

(2) You may demonstrate compliance 

by emissions averaging among the 

existing EGUs in the same subcategory, 

if your averaged Hg emissions for EGUs 

in the ‘‘unit designed for coal ≥ 8,300 

Btu/lb’’ subcategory are equal to or less 

than 1.0 lb/TBtu or 1.1E–2 lb/GWh or if 

your averaged emissions of individual, 

other pollutants from other 

subcategories of such EGUs are equal to 

or less than the applicable emissions 

limit in Table 2, according to the 

procedures in this section. Note that 

except for Hg emissions from EGUs in 

the ‘‘unit designed for coal ≥ 8,300 Btu/ 

lb’’ subcategory, the averaging time for 

emissions averaging for pollutants is 30 

days (rolling daily) using data from 

CEMS or a combination of data from 

CEMS and manual performance testing. 

The averaging time for emissions 

averaging for Hg from EGUs in the ‘‘unit 

designed for coal ≥ 8,300 Btu/lb’’ 

subcategory is 90 days (rolling daily) 

using data from CEMS, sorbent trap 

monitoring, or a combination of 

monitoring data and data from manual 

performance testing. For the purposes of 

this paragraph, 30- (or 90-day) group 

boiler operating days is defined as a 

period during which at least one unit in 

the emissions averaging group has 

operated 30 (or 90) days. You must 

calculate the weighted average 

emissions rate for the group in 

accordance with the procedures in this 

paragraph using the data from all units 

in the group including any that operate 

fewer than 30 (or 90) days during the 

preceding 30 (or 90) group boiler days. 

(i) You may choose to have your EGU 

emissions averaging group meet either 

the heat input basis (MMBtu or TBtu, as 

appropriate for the pollutant) or gross 

electrical output basis (MWh or GWh, as 

appropriate for the pollutant). 

(ii) You may not mix bases within 

your EGU emissions averaging group. 

(iii) You may use emissions averaging 

for affected units in different 

subcategories if the units vent to the 

atmosphere through a common stack 

(see paragraph (m) of this section). 

(b) Equations. Use the following 

equations when performing calculations 

for your EGU emissions averaging 

group: 

(1) Group eligibility equations. 

Where: 

WAERm = Weighted average emissions rate 

maximum in terms of lb/heat input or lb/ 

gross electrical output, 

Hermi = Hourly emissions rate (e.g., lb/ 

MMBtu, lb/MWh) from CEMS or sorbent 

trap monitoring for hour i, 

Rmmi = Maximum rated heat input or gross 

electrical output of unit i in terms of heat 

input or gross electrical output, 

p = number of EGUs in emissions averaging 

group that rely on CEMS, 

n = number of hourly rates collected over 30- 

group boiler operating days, 

Teri = Emissions rate from most recent test 

of unit i in terms of lb/heat input or lb/ 

gross electrical output, 

Rmti = Maximum rated heat input or gross 

electrical output of unit i in terms of lb/ 

heat input or lb/gross electrical output, 

and 

m = number of EGUs in emissions averaging 

group that rely on emissions testing. 


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9474 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

Where: 

variables with similar names share the 

descriptions for Equation 1a, 

Smmi = maximum steam generation in units 

of pounds from unit i that uses CEMS or 

sorbent trap monitoring, 

Cfmi = conversion factor, calculated from the 

most recent emissions test results, in 

units of heat input per pound of steam 

generated or gross electrical output per 

pound of steam generated, from unit i 

that uses CEMS or sorbent trap 

monitoring, 

Smti = maximum steam generation in units 

of pounds from unit i that uses emissions 

testing, and 

Cfti = conversion factor, calculated from the 

most recent emissions test results, in 

units of heat input per pound of steam 

generated or gross electrical output per 

pound of steam generated, from unit i 

that uses emissions testing. 

(2) Weighted 30-day rolling average 

emissions rate equations for pollutants 

other than Hg. Use equation 2a or 2b to 

calculate the 30-day rolling average 

emissions daily. 

Where: 

Heri = hourly emission rate (e.g., lb/MMBtu, 

lb/MWh) from unit i’s CEMS for the 

preceding 30-group boiler operating 

days, 

Rmi = hourly heat input or gross electrical 

output from unit i for the preceding 30- 

group boiler operating days, 

p = number of EGUs in emissions averaging 

group that rely on CEMS or sorbent trap 

monitoring, 

n = number of hourly rates collected over 30- 

group boiler operating days, 

Teri = Emissions rate from most recent 

emissions test of unit i in terms of lb/ 

heat input or lb/gross electrical output, 

Rti = Maximum rated heat input or gross 

electrical output of unit i in terms of lb/ 

heat input or lb/gross electrical output, 

and 

m = number of EGUs in emissions averaging 

group that rely on emissions testing. 

Where: 

variables with similar names share the 

descriptions for Equation 2a, 

Smi = steam generation in units of pounds 

from unit i that uses CEMS for the 

preceding 30-group boiler operating 

days, 

Cfmi = conversion factor, calculated from the 

most recent compliance test results, in 

units of heat input per pound of steam 

generated or gross electrical output per 

pound of steam generated, from unit i 

that uses CEMS from the preceding 30- 

group boiler operating days, 

Sti = steam generation in units of pounds 

from unit i that uses emissions testing, 

and 

Cfti = conversion factor, calculated from the 

most recent compliance test results, in 

units of heat input per pound of steam 

generated or gross electrical output per 

pound of steam generated, from unit i 

that uses emissions testing. 

(3) Weighted 90-boiler operating day 

rolling average emissions rate equations 

for Hg emissions from EGUs in the ‘‘unit 

designed for coal ≥ 8,300 Btu/lb’’ 

subcategory. Use equation 3a or 3b to 

calculate the 90-day rolling average 

emissions daily. 

Where: 

Heri = hourly emission rate from unit i’s 

CEMS or Hg sorbent trap monitoring for 

the preceding 90-group boiler operating 

days, 

Rmi = hourly heat input or gross electrical 

output from unit i for the preceding 90- 

group boiler operating days, 

p = number of EGUs in emissions averaging 

group that rely on CEMS, 

n = number of hourly rates collected over the 

90-group boiler operating days, 

Teri = Emissions rate from most recent 

emissions test of unit i in terms of lb/ 

heat input or lb/gross electrical output, 

Rti = Maximum rated heat input or gross 

electrical output of unit i in terms of lb/ 

heat input or lb/gross electrical output, 

and 

m = number of EGUs in emissions averaging 

group that rely on emissions testing. 


srobinson on DSK4SPTVN1PROD with RULES2ER16FE12.004</GPH> ER16FE12.005</GPH> ER16FE12.006</GPH> ER16FE12.007</GPH> ER16FE12.008</GPH>
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9475 

Where: 

variables with similar names share the 

descriptions for Equation 2a, 

Smi = steam generation in units of pounds 

from unit i that uses CEMS or a Hg 

sorbent trap monitoring for the preceding 

90-group boiler operating days, 

Cfmi = conversion factor, calculated from the 

most recent compliance test results, in 

units of heat input per pound of steam 

generated or gross electrical output per 

pound of steam generated, from unit i 

that uses CEMS or sorbent trap 

monitoring from the preceding 90-group 

boiler operating days, 

Sti = steam generation in units of pounds 

from unit i that uses emissions testing, 

and 

Cfti = conversion factor, calculated from the 

most recent emissions test results, in 

units of heat input per pound of steam 

generated or gross electrical output per 

pound of steam generated, from unit i 

that uses emissions testing. 

(c) Separate stack requirements. For a 

group of two or more existing EGUs in 

the same subcategory that each vent to 

a separate stack, you may average 

filterable PM, SO2, HF, HCl, 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 (d) 

through (j) of this section. 

(d) For each existing EGU in the 

averaging group: 

(1) The emissions rate achieved 

during the initial performance test for 

the HAP being averaged must not 

exceed the emissions level that was 

being achieved 180 days after April 16, 

2015, or the date on which emissions 

testing done to support your emissions 

averaging plan is complete (if the 

Administrator does not require 

submission and approval of your 

emissions averaging plan), or the date 

that you begin emissions averaging, 

whichever is earlier; or 

(2) The control technology employed 

during the initial performance test must 

not be less than the design efficiency of 

the emissions control technology 

employed 180 days after April 16, 2015 

or the date that you begin emissions 

averaging, whichever is earlier. 

(e) The weighted-average emissions 

rate from the existing EGUs 

participating in the emissions averaging 

option must be in compliance with the 

limits in Table 2 to this subpart at all 

times following the compliance date 

specified 180 days after April 16, 2015, 

or the date on which you complete the 

emissions measurements used to 

support your emissions averaging plan 

(if the Administrator does not require 

submission and approval of your 

emissions averaging plan), or the date 

that you begin emissions averaging, 

whichever is earlier. 

(f) Emissions averaging group 

eligibility demonstration. You must 

demonstrate the ability for the EGUs 

included in the emissions averaging 

group to demonstrate initial compliance 

according to paragraph (f)(1) or (2) of 

this section using the maximum normal 

operating load of each EGU and the 

results of the initial performance tests. 

For this demonstration and prior to 

submitting your emissions averaging 

plan, if requested, you must conduct 

required emissions monitoring for 30 

days of boiler operation and any 

required manual performance testing to 

calculate an initial weighted average 

emissions rate in accordance with this 

section. Should the Administrator 

require approval, you must submit your 

proposed emissions averaging plan and 

supporting data at least 120 days before 

April 16, 2015. If the Administrator 

requires approval of your plan, you may 

not begin using emissions averaging 

until the Administrator approves your 

plan. 

(1) You must use Equation 1a in 

paragraph (b) of this section to 

demonstrate that the maximum 

weighted average emissions rates of 

filterable PM, HF, SO2, HCl, non-Hg 

HAP metals, or Hg emissions from the 

existing units participating in the 

emissions averaging option do not 

exceed the emissions limits in Table 2 

to this subpart. 

(2) If you are not capable of 

monitoring heat input or gross electrical 

output, and the EGU generates steam for 

purposes other than generating 

electricity, you may use Equation 1b of 

this section as an alternative to using 

Equation 1a of this section to 

demonstrate that the maximum 

weighted average emissions rates of 

filterable PM, HF, SO2, HCl, non-Hg 

HAP metals, or Hg emissions from the 

existing units participating in the 

emissions averaging group do not 

exceed the emission limits in Table 2 to 

this subpart. 

(g) You must determine the weighted 

average emissions rate in units of the 

applicable emissions limit on a 30 day 

rolling average (90 day rolling average 

for Hg) basis according to paragraphs 

(f)(1) through (3) of this section. The 

first averaging period begins on 30 (or 

90 for Hg) days after February 16, 2015 

or the date that you begin emissions 

averaging, whichever is earlier. 

(1) You must use Equation 2a or 3a of 

paragraph (b) of this section to calculate 

the weighted average emissions rate 

using the actual heat input or gross 

electrical output for each existing unit 

participating in the emissions averaging 

option. 

(2) If you are not capable of 

monitoring heat input or gross electrical 

output, you may use Equation 2b or 3b 

of paragraph (b) of this section as an 

alternative to using Equation 2a of 

paragraph (b) of this section to calculate 

the average weighted emission rate 

using the actual steam generation from 

the units participating in the emissions 

averaging option. 

(h) CEMS (or sorbent trap monitoring) 

use. If an EGU in your emissions 

averaging group uses CEMS (or a 

sorbent trap monitor for Hg emissions) 

to demonstrate compliance, you must 

use those data to determine the 30 (or 

90) group boiler operating day rolling 

average emissions rate. 

(i) Emissions testing. If you use 

manual emissions testing to 

demonstrate compliance for one or more 

EGUs in your emissions averaging 

group, you must use the results from the 

most recent performance test to 

determine the 30 (or 90) day rolling 

average. You may use CEMS or sorbent 

trap data in combination with data from 

the most recent manual performance 

test in calculating the 30 (or 90) group 

boiler operating day rolling average 

emissions rate. 

(j) Emissions averaging plan. You 

must develop an implementation plan 

for emissions averaging according to the 

following procedures and requirements 

in paragraphs (j)(1) and (2) of this 

section. 

(1) You must include the information 

contained in paragraphs (j)(1)(i) through 

(v) of this section in your 

implementation plan for all the 

emissions units included in an 

emissions averaging: 

(i) The identification of all existing 

EGUs in the emissions averaging group, 

including for each either the applicable 

HAP emission level or the control 

technology installed as of 180 days after 

February 16, 2015, or the date on which 

you complete the emissions 

measurements used to support your 

emissions averaging plan (if the 

Administrator does not require 

submission and approval of your 

emissions averaging plan), or the date 

that you begin emissions averaging, 

whichever is earlier; and the date on 

which you are requesting emissions 

averaging to commence; 

(ii) The process weighting parameter 

(heat input, gross electrical output, or 

steam generated) that will be monitored 

for each averaging group; 

(iii) The specific control technology or 

pollution prevention measure to be used 

for each emission EGU in the averaging 

group and the date of its installation or 

application. If the pollution prevention 

measure reduces or eliminates 


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emissions from multiple EGUs, you 

must identify each EGU; 

(iv) The means of measurement (e.g., 

CEMS, sorbent trap monitoring, manual 

performance test) of filterable PM, SO2, 

HF, HCl, individual or total non-Hg 

HAP metals, or Hg emissions in 

accordance with the requirements in 

§ 63.10007 and to be used in the 

emissions averaging calculations; and 

(v) A demonstration that emissions 

averaging can produce compliance with 

each of the applicable emission limit(s) 

in accordance with paragraph (b)(1) of 

this section. 

(2) If the Administrator requests you 

to submit the plan for review and 

approval, you must submit a complete 

implementation plan at least 120 days 

before April 16, 2015. If the 

Administrator requests you to submit 

the plan for review and approval, you 

must receive approval before initiating 

emissions averaging. 

(i) The Administrator shall use 

following criteria in reviewing and 

approving or disapproving the plan: 

(A) Whether the content of the plan 

includes all of the information specified 

in paragraph (h)(1) of this section; and 

(B) Whether the plan presents 

information sufficient to determine that 

compliance will be achieved and 

maintained. 

(ii) The Administrator shall not 

approve an emissions averaging 

implementation plan containing any of 

the following provisions: 

(A) Any averaging between emissions 

of different pollutants or between units 

located at different facilities; or 

(B) The inclusion of any emissions 

unit other than an existing unit in the 

same subcategory. 

(k) Common stack requirements. For a 

group of two or more existing affected 

units, each of which vents through a 

single common stack, you may average 

emissions to demonstrate compliance 

with the limits in Table 2 to this subpart 

if you satisfy the requirements in 

paragraph (l) or (m) of this section. 

(l) For a group of two or more existing 

units in the same subcategory and 

which vent through a common 

emissions control system to a common 

stack that does not receive emissions 

from units in other subcategories or 

categories, you may treat such averaging 

group as a single existing unit for 

purposes of this subpart and comply 

with the requirements of this subpart as 

if the group were a single unit. 

(m) For all other groups of units 

subject to paragraph (k) of this section, 

you may elect to conduct manual 

performance tests according to 

procedures specified in § 63.10007 in 

the common stack. If emissions from 

affected units included in the emissions 

averaging and from other units not 

included in the emissions averaging 

(e.g., in a different subcategory) or other 

nonaffected units all vent to the 

common stack, you must shut down the 

units not included in the emissions 

averaging and the nonaffected units or 

vent their emissions to a different stack 

during the performance test. 

Alternatively, you may conduct a 

performance test of the combined 

emissions in the common stack with all 

units operating and show that the 

combined emissions meet the most 

stringent emissions limit. You may also 

use a CEMS or sorbent trap monitoring 

to apply this latter alternative to 

demonstrate that the combined 

emissions comply with the most 

stringent emissions limit on a 

continuous basis. 

(n) Combination requirements. The 

common stack of a group of two or more 

existing EGUs in the same subcategory 

subject to paragraph (k) of this section 

may be treated as a single stack for 

purposes of paragraph (c) of this section 

and included in an emissions averaging 

group subject to paragraph (c) of this 

section. 

§ 63.10010 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

(a) Flue gases from the affected units 

under this subpart exhaust to the 

atmosphere through a variety of 

different configurations, including but 

not limited to individual stacks, a 

common stack configuration or a main 

stack plus a bypass stack. For the CEMS, 

PM CPMS, and sorbent trap monitoring 

systems used to provide data under this 

subpart, the continuous monitoring 

system installation requirements for 

these exhaust configurations are as 

follows: 

(1) Single unit-single stack 

configurations. For an affected unit that 

exhausts to the atmosphere through a 

single, dedicated stack, you shall either 

install the required CEMS, PM CPMS, 

and sorbent trap monitoring systems in 

the stack or at a location in the 

ductwork downstream of all emissions 

control devices, where the pollutant and 

diluents concentrations are 

representative of the emissions that exit 

to the atmosphere. 

(2) Unit utilizing common stack with 

other affected unit(s). When an affected 

unit utilizes a common stack with one 

or more other affected units, but no nonaffected units, you shall either: 

(i) Install the required CEMS, PM 

CPMS, and sorbent trap monitoring 

systems in the duct leading to the 

common stack from each unit; or 

(ii) Install the required CEMS, PM 

CPMS, and sorbent trap monitoring 

systems in the common stack. 

(3) Unit(s) utilizing common stack 

with non-affected unit(s). 

(i) When one or more affected units 

shares a common stack with one or 

more non-affected units, you shall 

either: 

(A) Install the required CEMS, PM 

CPMS, and sorbent trap monitoring 

systems in the ducts leading to the 

common stack from each affected unit; 

or 

(B) Install the required CEMS, PM 

CPMS, and sorbent trap monitoring 

systems described in this section in the 

common stack and attribute all of the 

emissions measured at the common 

stack to the affected unit(s). 

(ii) If you choose the common stack 

monitoring option: 

(A) For each hour in which valid data 

are obtained for all parameters, you 

must calculate the pollutant emission 

rate and 

(B) You must assign the calculated 

pollutant emission rate to each unit that 

shares the common stack. 

(4) Unit with a main stack and a 

bypass stack. If the exhaust 

configuration of an affected unit 

consists of a main stack and a bypass 

stack, you shall install CEMS on both 

the main stack and the bypass stack, or, 

if it is not feasible to certify and qualityassure the data from a monitoring 

system on the bypass stack, you shall 

install a CEMS only on the main stack 

and count bypass hours of deviation 

from the monitoring requirements. 

(5) Unit with a common control 

device with multiple stack or duct 

configuration. If the flue gases from an 

affected unit, which is configured such 

that emissions are controlled with a 

common control device or series of 

control devices, are discharged to the 

atmosphere through more than one 

stack or are fed into a single stack 

through two or more ducts, you may: 

(i) Install required CEMS, PM CPMS, 

and sorbent trap monitoring systems in 

each of the multiple stacks; 

(ii) Install required CEMS, PM CPMS, 

and sorbent trap monitoring systems in 

each of the ducts that feed into the 

stack; 

(iii) Install required CEMS, PM CPMS, 

and sorbent trap monitoring systems in 

one of the multiple stacks or ducts and 

monitor the flows and dilution rates in 

all multiple stacks or ducts in order to 

determine total exhaust gas flow rate 

and pollutant mass emissions rate in 

accordance with the applicable limit; or 

(iv) In the case of multiple ducts 

feeding into a single stack, install 

CEMS, PM CPMS, and sorbent trap 


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monitoring systems in the single stack 

as described in paragraph (a)(1) of this 

section. 

(6) Unit with multiple parallel control 

devices with multiple stacks. If the flue 

gases from an affected unit, which is 

configured such that emissions are 

controlled with multiple parallel control 

devices or multiple series of control 

devices are discharged to the 

atmosphere through more than one 

stack, you shall install the required 

CEMS, PM CPMS, and sorbent trap 

monitoring systems described in each of 

the multiple stacks. You shall calculate 

hourly flow-weighted average pollutant 

emission rates for the unit as follows: 

(i) Calculate the pollutant emission 

rate at each stack or duct for each hour 

in which valid data are obtained for all 

parameters; 

(ii) Multiply each calculated hourly 

pollutant emission rate at each stack or 

duct by the corresponding hourly stack 

gas flow rate at that stack or duct; 

(iii) Sum the products determined 

under paragraph (a)(5)(iii)(B) of this 

section; and 

(iv) Divide the result obtained in 

paragraph (a)(5)(iii)(C) of this section by 

the total hourly stack gas flow rate for 

the unit, summed across all of the stacks 

or ducts. 

(b) If you use an oxygen (O2) or carbon 

dioxide (CO2) CEMS to convert 

measured pollutant concentrations to 

the units of the applicable emissions 

limit, the O2 or CO2 concentrations shall 

be monitored at a location that 

represents emissions to the atmosphere, 

i.e., at the outlet of the EGU, 

downstream of all emission control 

devices. You must install, certify, 

maintain, and operate the CEMS 

according to part 75 of this chapter. Use 

only quality-assured O2 or CO2 data in 

the emissions calculations; do not use 

part 75 substitute data values. 

(c) If you are required to use a stack 

gas flow rate monitor, either for routine 

operation of a sorbent trap monitoring 

system or to convert pollutant 

concentrations to units of an electrical 

output-based emission standard in 

Table 1 or 2 to this subpart, you must 

install, certify, operate, and maintain 

the monitoring system and conduct ongoing quality-assurance testing of the 

system according to part 75 of this 

chapter. Use only unadjusted, qualityassured flow rate data in the emissions 

calculations. Do not apply bias 

adjustment factors to the flow rate data 

and do not use substitute flow rate data 

in the calculations. 

(d) If you are required to make 

corrections for stack gas moisture 

content when converting pollutant 

concentrations to the units of an 

emission standard in Table 1 of 2 to this 

subpart, you must install, certify, 

operate, and maintain a moisture 

monitoring system in accordance with 

part 75 of this chapter. Alternatively, for 

coal-fired units, you may use 

appropriate fuel-specific default 

moisture values from § 75.11(b) of this 

chapter to estimate the moisture content 

of the stack gas or you may petition the 

Administrator under § 75.66 of this 

chapter for use of a default moisture 

value for non-coal-fired units. If you 

install and operate a moisture 

monitoring system, do not use substitute 

moisture data in the emissions 

calculations. 

(e) If you use an HCl and/or HF 

CEMS, you must install, certify, operate, 

maintain, and quality-assure the data 

from the monitoring system in 

accordance with appendix B to this 

subpart. Calculate and record a 30-boiler 

operating day rolling average HCl or HF 

emission rate in the units of the 

standard, updated after each new boiler 

operating day. Each 30-boiler operating 

day rolling average emission rate is the 

average of all the valid hourly HCl or HF 

emission rates in the preceding 30 boiler 

operating days (see section 9.4 of 

appendix B to this subpart). 

(f)(1) If you use an SO2 CEMS, you 

must install the monitor at the outlet of 

the EGU, downstream of all emission 

control devices, and you must certify, 

operate, and maintain the CEMS 

according to part 75 of this chapter. 

(2) For on-going QA, the SO2 CEMS 

must meet the applicable daily, 

quarterly, and semiannual or annual 

requirements in sections 2.1 through 2.3 

of appendix B to part 75 of this chapter, 

with the following addition: You must 

perform the linearity checks required in 

section 2.2 of appendix B to part 75 of 

this chapter if the SO2 CEMS has a span 

value of 30 ppm or less. 

(3) Calculate and record a 30-boiler 

operating day rolling average SO2

emission rate in the units of the 

standard, updated after each new boiler 

operating day. Each 30-boiler operating 

day rolling average emission rate is the 

average of all of the valid SO2 emission 

rates in the preceding 30 boiler 

operating days. 

(4) Use only unadjusted, qualityassured SO2 concentration values in the 

emissions calculations; do not apply 

bias adjustment factors to the part 75 

SO2 data and do not use part 75 

substitute data values. 

(g) If you use a Hg CEMS or a sorbent 

trap monitoring system, you must 

install, certify, operate, maintain and 

quality-assure the data from the 

monitoring system in accordance with 

appendix A to this subpart. You must 

calculate and record a 30-boiler 

operating day rolling average Hg 

emission rate, in units of the standard, 

updated after each new boiler operating 

day. Each 30-boiler operating day 

rolling average emission rate, calculated 

according to section 6.2 of appendix A 

to the subpart, is the average of all of the 

valid hourly Hg emission rates in the 

preceding 30 boiler operating days. 

Section 7.1.4.3 of appendix A to this 

subpart explains how to reduce sorbent 

trap monitoring system data to an 

hourly basis. 

(h) If you use a PM CPMS to 

demonstrate continuous compliance 

with an operating limit, you must 

install, calibrate, maintain, and operate 

the PM CPMS and record the output of 

the system as specified in paragraphs 

(h)(1) through (5) of this section. 

(1) Install, calibrate, operate, and 

maintain your PM CPMS according to 

the procedures in your approved sitespecific monitoring plan developed in 

accordance with § 63.10000(d), and 

meet the requirements in paragraphs 

(h)(1)(i) through (iii) of this section. 

(i) The operating principle of the PM 

CPMS must be based on in-stack or 

extractive light scatter, light 

scintillation, beta attenuation, or mass 

accumulation detection of the exhaust 

gas or representative sample. The 

reportable measurement output from the 

PM CPMS may be expressed as 

milliamps, stack concentration, or other 

raw data signal. 

(ii) The PM CPMS must have a cycle 

time (i.e., period required to complete 

sampling, measurement, and reporting 

for each measurement) no longer than 

60 minutes. 

(iii) The PM CPMS must be capable, 

at a minimum, of detecting and 

responding to particulate matter 

concentrations of 0.5 mg/acm. 

(2) For a new unit, complete the 

initial PM CPMS performance 

evaluation no later than October 13, 

2012 or 180 days after the date of initial 

startup, whichever is later. For an 

existing unit, complete the initial 

performance evaluation no later than 

October 13, 2015. 

(3) Collect PM CPMS hourly average 

output data for all boiler operating 

hours except as indicated in paragraph 

(h)(5) of this section. Express the PM 

CPMS output as milliamps, PM 

concentration, or other raw data signal 

value. 

(4) Calculate the arithmetic 30-boiler 

operating day rolling average of all of 

the hourly average PM CPMS output 

collected during all nonexempt boiler 

operating hours data (e.g., milliamps, 

PM concentration, raw data signal). 


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(5) You must collect data using the 

PM CPMS at all times the process unit 

is operating and at the intervals 

specified in paragraph (h)(1)(ii) of this 

section, except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

required monitoring system quality 

assurance or quality control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments), and any scheduled 

maintenance as defined in your sitespecific monitoring plan. 

(6) You must use all the data collected 

during all boiler operating hours in 

assessing the compliance with your 

operating limit except: 

(i) Any data collected during 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, or required monitoring 

system quality assurance or quality 

control activities conducted during 

monitoring system malfunctions are not 

used in calculations (report any such 

periods in your annual deviation 

report); 

(ii) Any data collected during periods 

when the monitoring system is out of 

control as specified in your site-specific 

monitoring plan, repairs associated with 

periods when the monitoring system is 

out of control, or required monitoring 

system quality assurance or quality 

control activities conducted during outof-control periods are not used in 

calculations (report emissions or 

operating levels and report any such 

periods in your annual deviation 

report); 

(iii) Any data recorded during periods 

of startup or shutdown. 

(7) You must record and make 

available upon request results of PM 

CPMS system performance audits, as 

well as the dates and duration of 

periods from when the PM CPMS is out 

of control until completion of the 

corrective actions necessary to return 

the PM CPMS to operation consistent 

with your site-specific monitoring plan. 

(i) If you choose to comply with the 

PM filterable emissions limit in lieu of 

metal HAP limits, you may choose to 

install, certify, operate, and maintain a 

PM CEMS and record the output of the 

PM CEMS as specified in paragraphs 

(i)(1) through (5) of this section. The 

compliance limit will be expressed as a 

30-boiler operating day rolling average 

of the numerical emissions limit value 

applicable for your unit in tables 1 or 2 

to this subpart. 

(1) Install and certify your PM CEMS 

according to the procedures and 

requirements in Performance 

Specification 11—Specifications and 

Test Procedures for Particulate Matter 

Continuous Emission Monitoring 

Systems at Stationary Sources in 

Appendix B to part 60 of this chapter, 

using Method 5 at Appendix A–3 to part 

60 of this chapter and ensuring that the 

front half filter temperature shall be 

160° ± 14°C (320° ± 25°F). The 

reportable measurement output from the 

PM CEMS must be expressed in units of 

the applicable emissions limit (e.g., lb/ 

MMBtu, lb/MWh). 

(2) Operate and maintain your PM 

CEMS according to the procedures and 

requirements in Procedure 2—Quality 

Assurance Requirements for Particulate 

Matter Continuous Emission Monitoring 

Systems at Stationary Sources in 

Appendix F to part 60 of this chapter. 

(i) You must conduct the relative 

response audit (RRA) for your PM CEMS 

at least once annually. 

(ii) You must conduct the relative 

correlation audit (RCA) for your PM 

CEMS at least once every 3 years. 

(3) Collect PM CEMS hourly average 

output data for all boiler operating 

hours except as indicated in paragraph 

(i) of this section. 

(4) Calculate the arithmetic 30-boiler 

operating day rolling average of all of 

the hourly average PM CEMS output 

data collected during all nonexempt 

boiler operating hours. 

(5) You must collect data using the 

PM CEMS at all times the process unit 

is operating and at the intervals 

specified in paragraph (a) of this 

section, except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

and required monitoring system quality 

assurance or quality control activities. 

(i) You must use all the data collected 

during all boiler operating hours in 

assessing the compliance with your 

operating limit except: 

(A) Any data collected during 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, or required monitoring 

system quality assurance or control 

activities conducted during monitoring 

system malfunctions in calculations and 

report any such periods in your annual 

deviation report; 

(B) Any data collected during periods 

when the monitoring system is out of 

control as specified in your site-specific 

monitoring plan, repairs associated with 

periods when the monitoring system is 

out of control, or required monitoring 

system quality assurance or control 

activities conducted during out of 

control periods in calculations used to 

report emissions or operating levels and 

report any such periods in your annual 

deviation report; 

(C) Any data recorded during periods 

of startup or shutdown. 

(ii) You must record and make 

available upon request results of PM 

CEMS system performance audits, dates 

and duration of periods when the PM 

CEMS is out of control to completion of 

the corrective actions necessary to 

return the PM CEMS to operation 

consistent with your site-specific 

monitoring plan. 

(j) You may choose to comply with 

the metal HAP emissions limits using 

CEMS approved in accordance with 

§ 63.7(f) as an alternative to the 

performance test method specified in 

this rule. If approved to use a HAP 

metals CEMS, the compliance limit will 

be expressed as a 30-boiler operating 

day rolling average of the numerical 

emissions limit value applicable for 

your unit in tables 1 or 2. If approved, 

you may choose to install, certify, 

operate, and maintain a HAP metals 

CEMS and record the output of the HAP 

metals CEMS as specified in paragraphs 

(j)(1) through (5) of this section. 

(1)(i) Install and certify your HAP 

metals CEMS according to the 

procedures and requirements in you 

approved site specific test plan as 

required in § 63.7(e). The reportable 

measurement output from the HAP 

metals CEMS must be expressed in units 

of the applicable emissions limit (e.g., 

lb/MMBtu, lb/MWh) and in the form of 

a 30-boiler operating day rolling 

average. 

(ii) Operate and maintain your HAP 

metals CEMS according to the 

procedures and criteria in your site 

specific performance evaluation and 

quality control program plan required in 

§ 63.8(d). 

(2) Collect HAP metals CEMS hourly 

average output data for all boiler 

operating hours except as indicated in 

section (j)(4) of this section. 

(3) Calculate the arithmetic 30-boiler 

operating day rolling average of all of 

the hourly average HAP metals CEMS 

output data collected during all 

nonexempt boiler operating hours data. 

(4) You must collect data using the 

HAP metals CEMS at all times the 

process unit is operating and at the 

intervals specified in paragraph (a) of 

this section, except for periods of 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, and required monitoring 

system quality assurance or quality 

control activities. 

(i) You must use all the data collected 

during all boiler operating hours in 

assessing the compliance with your 

emission limit except: 

(A) Any data collected during 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, or required monitoring 


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system quality assurance or control 

activities conducted during monitoring 

system malfunctions in calculations and 

report any such periods in your annual 

deviation report; 

(B) Any data collected during periods 

when the monitoring system is out of 

control as specified in your site-specific 

monitoring plan, repairs associated with 

periods when the monitoring system is 

out of control, or required monitoring 

system quality assurance or control 

activities conducted during out of 

control periods in calculations used to 

report emissions or operating levels and 

report any such periods in your annual 

deviation report; 

(C) Any data recorded during periods 

of startup or shutdown. 

(ii) You must record and make 

available upon request results of HAP 

metals CEMS system performance 

audits, dates and duration of periods 

when the HAP metals CEMS is out of 

control to completion of the corrective 

actions necessary to return the HAP 

metals CEMS to operation consistent 

with your site-specific performance 

evaluation and quality control program 

plan. 

(k) If you demonstrate compliance 

with the HCl and HF emission limits for 

a liquid oil-fired EGU by conducting 

quarterly testing, you must also develop 

a site-specific monitoring plan as 

provided for in § 63.10000(c)(2)(iii) and 

Table 7 to this subpart. 

§ 63.10011 How do I demonstrate initial 

compliance with the emissions limits and 

work practice standards? 

(a) You must demonstrate initial 

compliance with each emissions limit 

that applies to you by conducting 

performance testing. 

(b) If you are subject to an operating 

limit in Table 4 to this subpart, you 

demonstrate initial compliance with 

HAP metals or filterable PM emission 

limit(s) through performance stack tests 

and you elect to use a PM CPMS to 

demonstrate continuous performance, or 

if, for a liquid oil-fired unit, and you use 

quarterly stack testing for HCl and HF 

plus site-specific parameter monitoring 

to demonstrate continuous performance, 

you must also establish a site-specific 

operating limit, in accordance with 

Table 4 to this subpart, § 63.10007, and 

Table 6 to this subpart. You may use 

only the parametric data recorded 

during successful performance tests 

(i.e., tests that demonstrate compliance 

with the applicable emissions limits) to 

establish an operating limit. 

(c)(1) If you use CEMS or sorbent trap 

monitoring systems to measure a HAP 

(e.g., Hg or HCl) directly, the first 30- 

boiler operating day rolling average 

emission rate obtained with certified 

CEMS after the applicable date in 

§ 63.9984 (or, if applicable, prior to that 

date, as described in § 63.10005(b)(2)), 

expressed in units of the standard, is the 

initial performance test. Initial 

compliance is demonstrated if the 

results of the performance test meet the 

applicable emission limit in Table 1 or 

2 to this subpart. 

(2) For a unit that uses a CEMS to 

measure SO2 or PM emissions for initial 

compliance, the first 30 boiler operating 

day average emission rate obtained with 

certified CEMS after the applicable date 

in § 63.9984 (or, if applicable, prior to 

that date, as described in 

§ 63.10005(b)(2)), expressed in units of 

the standard, is the initial performance 

test. Initial compliance is demonstrated 

if the results of the performance test 

meet the applicable SO2 or filterable PM 

emission limit in Table 1 or 2 to this 

subpart. 

(d) For candidate LEE units, use the 

results of the performance testing 

described in § 63.10005(h) to determine 

initial compliance with the applicable 

emission limit(s) in Table 1 or 2 to this 

subpart and to determine whether the 

unit qualifies for LEE status. 

(e) You must submit a Notification of 

Compliance Status containing the 

results of the initial compliance 

demonstration, according to 

§ 63.10030(e). 

(f)(1) You must determine the fuel 

whose combustion produces the least 

uncontrolled emissions, i.e., the 

cleanest fuel, either natural gas or 

distillate oil, that is available on site or 

accessible nearby for use during periods 

of startup or shutdown. 

(2) Your cleanest fuel, either natural 

gas or distillate oil, for use during 

periods of startup or shutdown 

determination may take safety 

considerations into account. 

(g) You must follow the startup or 

shutdown requirements given in Table 3 

for each coal-fired, liquid oil-fired, and 

solid oil-derived fuel-fired EGU. 

Continuous Compliance Requirements 

§ 63.10020 How do I monitor and collect 

data to demonstrate continuous 

compliance? 

(a) You must monitor and collect data 

according to this section and the sitespecific 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 outof-control periods (see § 63.8(c)(7) of 

this part), and required monitoring 

system quality assurance or quality 

control activities, including, as 

applicable, calibration checks and 

required zero and span adjustments. 

You are required to affect monitoring 

system repairs in response to 

monitoring system malfunctions and to 

return the monitoring system to 

operation as expeditiously as 

practicable. 

(c) You may not use data recorded 

during EGU startup or shutdown or 

monitoring system malfunctions or 

monitoring system out-of-control 

periods, repairs associated with 

monitoring system malfunctions or 

monitoring system out-of-control 

periods, or required monitoring system 

quality assurance or control activities in 

calculations used to report emissions or 

operating levels. You must use all the 

data collected during all other periods 

in assessing the operation of the control 

device and associated control system. 

(d) Except for periods of monitoring 

system malfunctions or monitoring 

system out-of-control periods, repairs 

associated with monitoring system 

malfunctions or monitoring system outof-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) Except as otherwise provided in 

§ 63.10020(c), if you use a CEMS to 

measure SO2, PM, HCl, HF, or Hg 

emissions, or using a sorbent trap 

monitoring system to measure Hg 

emissions, you must demonstrate 

continuous compliance by using all 

quality-assured hourly data recorded by 

the CEMS (or sorbent trap monitoring 

system) and the other required 

monitoring systems (e.g., flow rate, CO2, 

O2, or moisture systems) to calculate the 

arithmetic average emissions rate in 

units of the standard on a continuous 

30-boiler operating day rolling average 

basis, updated at the end of each new 

boiler operating day. Use Equation 8 to 

determine the 30-boiler operating day 

rolling average. 


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Where: 

Heri is the hourly emissions rate for hour i 

and n is the number of hourly emissions 

rate values collected over 30 boiler 

operating days. 

(c) If you use a PM CPMS data to 

measure compliance with an operating 

limit in Table 4 to this subpart, you 

must record the PM CPMS output data 

for all periods when the process is 

operating and the PM CPMS is not outof-control. You must demonstrate 

continuous compliance by using all 

quality-assured hourly average data 

collected by the PM CPMS for all 

operating hours to calculate the 

arithmetic average operating parameter 

in units of the operating limit (e.g., 

milliamps, PM concentration, raw data 

signal) on a 30 operating day rolling 

average basis, updated at the end of 

each new boiler operating day. Use 

Equation 9 to determine the 30 boiler 

operating day average. 

Where: 

Hpvi is the hourly parameter value for hour 

i and n is the number of valid hourly 

parameter values collected over 30 boiler 

operating days. 

(d) If you use quarterly performance 

testing to demonstrate compliance with 

one or more applicable emissions limits 

in Table 1 or 2 to this subpart, you 

(1) May skip performance testing in 

those quarters during which less than 

168 boiler operating hours occur, except 

that a performance test must be 

conducted at least once every calendar 

year. 

(2) Must conduct the performance test 

as defined in Table 5 to this subpart and 

calculate the results of the testing in 

units of the applicable emissions 

standard; and 

(3) Must conduct site-specific 

monitoring for a liquid oil-fired unit to 

ensure compliance with the HCl and HF 

emission limits in Tables 1 and 2 to this 

subpart, in accordance with the 

requirements of § 63.10000(c)(2)(iii). 

The monitoring must meet the general 

operating requirements provided in 

§ 63.10020(a). 

(e) If you must conduct periodic 

performance tune-ups of your EGU(s), as 

specified in paragraphs (e)(1) through 

(9) of this section, perform the first tuneup as part of your initial compliance 

demonstration. Notwithstanding this 

requirement, you may delay the first 

burner inspection until the next 

scheduled unit outage provided you 

meet the requirements of § 63.10005. 

Subsequently, you must perform an 

inspection of the burner at least once 

every 36 calendar months unless your 

EGU employs neural network 

combustion optimization during normal 

operations in which case you must 

perform an inspection of the burner and 

combustion controls at least once every 

48 calendar months. 

(1) 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: 

(i) Burner or combustion control 

component parts needing replacement 

that affect the ability to optimize NOX

and CO must be installed within 3 

calendar months after the burner 

inspection, 

(ii) 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 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 

network or combustion efficiency 

software, control systems calibrations, 

adjusting combustion zone temperature 

profiles, and add-on controls such as 

SCR and SNCR; CO optimization 

includes burners, overfire air controls, 

concentric firing system improvements, 

neural network or combustion efficiency 

software, control systems calibrations, 

and adjusting combustion zone 

temperature profiles; 

(7) While operating at full load or the 

predominantly operated load, measure 

the concentration in the effluent stream 

of CO and NOX in ppm, by volume, and 

oxygen in volume percent, before and 

after the tune-up adjustments are made 

(measurements may be either on a dry 

or wet basis, as long as it is the same 

basis before and after the adjustments 

are made). You may use portable CO, 

NOX and O2 monitors for this 

measurement. EGU’s employing neural 

network optimization systems need only 

provide a single pre- and post-tune-up 

value rather than continual values 

before and after each optimization 

adjustment made by the system; 

(8) Maintain on-site and submit, if 

requested by the Administrator, an 

annual report containing the 

information in paragraphs (e)(1) through 

(e)(9) of this section including: 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9481 

(i) The concentrations of CO and NOX

in the effluent stream in ppm by 

volume, and oxygen in volume percent, 

measured before and after an adjustment 

of the EGU combustion systems; 

(ii) A description of any corrective 

actions taken as a part of the 

combustion adjustment; and 

(iii) The type(s) and amount(s) of fuel 

used over the 12 calendar months prior 

to an adjustment, but only if the unit 

was physically and legally capable of 

using more than one type of fuel during 

that period; and 

(9) Report the dates of the initial and 

subsequent tune-ups as follows: 

(i) If the first required tune-up is 

performed as part of the initial 

compliance demonstration, report the 

date of the tune-up in hard copy (as 

specified in § 63.10030) and 

electronically (as specified in 

§ 63.10031). Report the date of each 

subsequent tune-up electronically (as 

specified in § 63.10031). 

(ii) If the first tune-up is not 

conducted as part of the initial 

compliance demonstration, but is 

postponed until the next unit outage, 

report the date of that tune-up and all 

subsequent tune-ups electronically, in 

accordance with § 63.10031. 

(f) You must submit the reports 

required under § 63.10031 and, if 

applicable, the reports required under 

appendices A and B to this subpart. The 

electronic reports required by 

appendices A and B to this subpart must 

be sent to the Administrator 

electronically in a format prescribed by 

the Administrator, as provided in 

§ 63.10031. CEMS data (except for PM 

CEMS and any approved alternative 

monitoring using a HAP metals CEMS) 

shall be submitted using EPA’s 

Emissions Collection and Monitoring 

Plan System (ECMPS) Client Tool. Other 

data, including PM CEMS data, HAP 

metals CEMS data, and CEMS 

performance test detail reports, shall be 

submitted in the file format generated 

through use of EPA’s Electronic 

Reporting Tool, the Compliance and 

Emissions Data Reporting Interface, or 

alternate electronic file format, all as 

provided for under § 63.10031. 

(g) You must report each instance in 

which you did not meet an applicable 

emissions limit or operating limit in 

Tables 1 through 4 to this subpart or 

failed to conduct a required tune-up. 

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 

emissions averaging provision? 

(a) Following the compliance date, the 

owner or operator must demonstrate 

compliance with this subpart on a 

continuous basis by meeting the 

requirements of paragraphs (a)(1) 

through (3) of this section. 

(1) For each calendar month, 

demonstrate compliance with the 

average weighted emissions limit for the 

existing units participating in the 

emissions averaging option as 

determined in § 63.10009(f) and (g); 

(2) For each existing unit participating 

in the emissions averaging option that is 

equipped with PM CPMS, maintain the 

average parameter value at or below the 

operating limit established during the 

most recent performance test; 

(3) For each existing unit participating 

in the emissions averaging option 

venting to a common stack 

configuration containing affected units 

from other subcategories, maintain the 

appropriate operating limit for each unit 

as specified in Table 4 to this subpart 

that applies. 

(b) Any instance where the owner or 

operator fails to comply with the 

continuous monitoring requirements in 

paragraphs (a)(1) through (3) of this 

section is a deviation. 

§ 63.10023 How do I establish my PM 

CPMS operating limit and determine 

compliance with it? 

(a) During the initial performance test 

or any such subsequent performance 

test that demonstrates compliance with 

the filterable PM, individual nonmercury HAP metals, or total nonmercury HAP metals limit (or for liquid 

oil-fired units, individual HAP metals or 

total HAP metals limit, including Hg) in 

Table 1 or 2, record all hourly average 

output values (e.g., milliamps, stack 

concentration, or other raw data signal) 

from the PM CPMS for the periods 

corresponding to the test runs (e.g., nine 

1-hour average PM CPMS output values 

for three 3-hour test runs). 

(b) Determine your operating limit as 

the highest 1-hour average PM CPMS 

output value recorded during the 

performance test. You must verify an 

existing or establish a new operating 

limit after each repeated performance 

test. 

(c) You must operate and maintain 

your process and control equipment 

such that the 30 operating day average 

PM CPMS output does not exceed the 

operating limit determined in 

paragraphs (a) and (b) of this section. 

Notification, Reports, and Records 

§ 63.10030 What notifications must I 

submit and when? 

(a) You must submit all of the 

notifications in §§ 63.7(b) and (c), 63.8 

(e), (f)(4) and (6), and 63.9 (b) through 

(h) that apply to you by the dates 

specified. 

(b) As specified in § 63.9(b)(2), if you 

startup your affected source before April 

16, 2012, you must submit an Initial 

Notification not later than 120 days after 

April 16, 2012. 

(c) As specified in § 63.9(b)(4) and 

(b)(5), if you startup your new or 

reconstructed affected source on or after 

April 16, 2012, you must submit an 

Initial Notification not later than 15 

days after the actual date of startup of 

the affected source. 

(d) When you are required to conduct 

a performance test, you must submit a 

Notification of Intent to conduct a 

performance test at least 30 days before 

the performance test is scheduled to 

begin. 

(e) When you are required to conduct 

an initial compliance demonstration as 

specified in § 63.10011(a), you must 

submit a Notification of Compliance 

Status according to § 63.9(h)(2)(ii). The 

Notification of Compliance Status report 

must contain all the information 

specified in paragraphs (e)(1) through 

(7), as applicable. 

(1) A description of the affected 

source(s) including identification of 

which subcategory the source is in, the 

design capacity of the source, a 

description of the add-on controls used 

on the source, description of the fuel(s) 

burned, including whether the fuel(s) 

were determined by you or EPA through 

a petition process to be a non-waste 

under 40 CFR 241.3, whether the fuel(s) 

were processed from discarded nonhazardous secondary materials within 

the meaning of 40 CFR 241.3, and 

justification for the selection of fuel(s) 

burned during the performance test. 

(2) Summary of the results of all 

performance tests and fuel analyses and 

calculations conducted to demonstrate 

initial compliance including all 

established operating limits. 

(3) Identification of whether you plan 

to demonstrate compliance with each 

applicable emission limit through 

performance testing; fuel moisture 

analyses; performance testing with 

operating limits (e.g., use of PM CPMS); 

CEMS; or a sorbent trap monitoring 

system. 

(4) Identification of whether you plan 

to demonstrate compliance by emissions 

averaging. 


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(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 brief description of the deviation, the 

duration of the deviation, emissions 

point identification, and the cause of the 

deviation in the Notification of 

Compliance Status report. 

(7) In addition to the information 

required in § 63.9(h)(2), your 

notification of compliance status must 

include the following: 

(i) A summary of the results of the 

annual performance tests and 

documentation of any operating limits 

that were reestablished during this test, 

if applicable. If you are conducting stack 

tests once every 3 years consistent with 

§ 63.10006(i), the date of the last three 

stack tests, a comparison of the emission 

level you achieved in the last three stack 

tests to the 50 percent emission limit 

threshold required in § 63.10006(i), and 

a statement as to whether there have 

been any operational changes since the 

last stack test that could increase 

emissions. 

(ii) Certifications of compliance, as 

applicable, and must be signed by a 

responsible official stating: 

(A) ‘‘This EGU complies with the 

requirements in § 63.10021(a) to 

demonstrate continuous compliance.’’ 

and 

(B) ‘‘No secondary materials that are 

solid waste were combusted in any 

affected unit.’’ 

§ 63.10031 What reports must I submit and 

when? 

(a) You must submit each report in 

Table 8 to this subpart that applies to 

you. If you are required to (or elect to) 

continuously monitor Hg and/or HCl 

and/or HF emissions, you must also 

submit the electronic reports required 

under appendix A and/or appendix B to 

the subpart, at the specified frequency. 

(b) Unless the Administrator has 

approved a different schedule for 

submission of reports under § 63.10(a), 

you must submit each report by the date 

in Table 8 to this subpart and according 

to the requirements in paragraphs (b)(1) 

through (5) of this section. 

(1) The first compliance report must 

cover the period beginning on the 

compliance date that is specified for 

your affected source in § 63.9984 and 

ending on June 30 or December 31, 

whichever date is the first date that 

occurs at least 180 days after the 

compliance date that is specified for 

your source in § 63.9984. 

(2) The first compliance report must 

be postmarked or submitted 

electronically no later than July 31 or 

January 31, whichever date is the first 

date following the end of the first 

calendar half after the compliance date 

that is specified for your source in 

§ 63.9984. 

(3) Each subsequent compliance 

report must cover the semiannual 

reporting period from January 1 through 

June 30 or the semiannual reporting 

period from July 1 through December 

31. 

(4) Each subsequent compliance 

report must be postmarked or submitted 

electronically no later than July 31 or 

January 31, whichever date is the first 

date following the end of the 

semiannual reporting period. 

(5) For each affected source that is 

subject to permitting regulations 

pursuant to part 70 or part 71 of this 

chapter, and if the permitting authority 

has established dates for submitting 

semiannual reports pursuant to 40 CFR 

70.6(a)(3)(iii)(A) or 40 CFR 

71.6(a)(3)(iii)(A), you may submit the 

first and subsequent compliance reports 

according to the dates the permitting 

authority has established instead of 

according to the dates in paragraphs 

(b)(1) through (4) of this section. 

(c) The compliance report must 

contain the information required in 

paragraphs (c)(1) through (4) of this 

section. 

(1) The information required by the 

summary report located in 

63.10(e)(3)(vi). 

(2) The total fuel use by each affected 

source subject to an emission limit, for 

each calendar month within the 

semiannual reporting period, including, 

but not limited to, a description of the 

fuel, whether the fuel has received a 

non-waste determination by EPA or 

your basis for concluding that the fuel 

is not a waste, and the total fuel usage 

amount with units of measure. 

(3) Indicate whether you burned new 

types of fuel during the reporting 

period. If you did burn new types of fuel 

you must include the date of the 

performance test where that fuel was in 

use. 

(4) Include the date of the most recent 

tune-up for each unit subject to the 

requirement to conduct a performance 

tune-up according to § 63.10021(e). 

Include the date of the most recent 

burner inspection if it was not done 

annually and was delayed until the next 

scheduled unit shutdown. 

(d) For each excess emissions 

occurring at an affected source where 

you are using a CMS to comply with 

that emission limit or operating limit, 

you must include the information 

required in § 63.10(e)(3)(v) in the 

compliance report specified in section 

(c). 

(e) Each affected source that has 

obtained a Title V operating permit 

pursuant to part 70 or part 71 of this 

chapter must report all deviations as 

defined in this subpart in the 

semiannual monitoring report required 

by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 

71.6(a)(3)(iii)(A). If an affected source 

submits a compliance report pursuant to 

Table 8 to this subpart along with, or as 

part of, the semiannual monitoring 

report required by 40 CFR 

70.6(a)(3)(iii)(A) or 40 CFR 

71.6(a)(3)(iii)(A), and the compliance 

report includes all required information 

concerning deviations from any 

emission limit, operating limit, or work 

practice requirement in this subpart, 

submission of the compliance report 

satisfies any obligation to report the 

same deviations in the semiannual 

monitoring report. Submission of a 

compliance report does not otherwise 

affect any obligation the affected source 

may have to report deviations from 

permit requirements to the permit 

authority. 

(f) As of January 1, 2012, and within 

60 days after the date of completing 

each performance test, you must submit 

the results of the performance tests 

required by this subpart to EPA’s 

WebFIRE database by using the 

Compliance and Emissions Data 

Reporting Interface (CEDRI) that is 

accessed through EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). 

Performance test data must be submitted 

in the file format generated through use 

of EPA’s Electronic Reporting Tool 

(ERT) (see http://www.epa.gov/ttn/chief/ 

ert/index.html). Only data collected 

using those test methods on the ERT 

Web site 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 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 


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in the format specified by the delegated 

authority. 

(1) Within 60 days after the date of 

completing each CEMS (SO2, PM, HCl, 

HF, and Hg) performance evaluation 

test, as defined in § 63.2 and required by 

this subpart, you must submit the 

relative accuracy test audit (RATA) data 

(or, for PM CEMS, RCA and RRA data) 

required by this subpart to EPA’s 

WebFIRE database by using the 

Compliance and Emissions Data 

Reporting Interface (CEDRI) that is 

accessed through EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). 

The RATA data shall be submitted in 

the file format generated through use of 

EPA’s Electronic Reporting Tool (ERT) 

(http://www.epa.gov/ttn/chief/ert/ 

index.html). Only RATA data 

compounds listed on the ERT Web site 

are subject to this requirement. Owners 

or operators who claim that some of the 

information being submitted for RATAs 

is confidential business information 

(CBI) shall submit a complete ERT file 

including information claimed to be CBI 

on a compact disk or other commonly 

used electronic storage media 

(including, but not limited to, flash 

drives) by registered letter to EPA and 

the same ERT file with the CBI omitted 

to EPA via CDX as described earlier in 

this paragraph. The compact disk or 

other commonly used electronic storage 

media shall be clearly marked as CBI 

and mailed to U.S. EPA/OAPQS/CORE 

CBI Office, Attention: WebFIRE 

Administrator, MD C404–02, 4930 Old 

Page Rd., Durham, NC 27703. At the 

discretion of the delegated authority, 

owners or operators shall also submit 

these RATAs to the delegated authority 

in the format specified by the delegated 

authority. Owners or operators shall 

submit calibration error testing, drift 

checks, and other information required 

in the performance evaluation as 

described in § 63.2 and as required in 

this chapter. 

(2) For a PM CEMS, PM CPMS, or 

approved alternative monitoring using a 

HAP metals CEMS, within 60 days after 

the reporting periods ending on March 

31st, June 30th, September 30th, and 

December 31st, you must submit 

quarterly reports to EPA’s WebFIRE 

database by using the Compliance and 

Emissions Data Reporting Interface 

(CEDRI) that is accessed through EPA’s 

Central Data Exchange (CDX) 

(www.epa.gov/cdx). You must use the 

appropriate electronic reporting form in 

CEDRI or provide an alternate electronic 

file consistent with EPA’s reporting 

form output format. For each reporting 

period, the quarterly reports must 

include all of the calculated 30-boiler 

operating day rolling average values 

derived from the CEMS and PM CPMS. 

(3) Reports for an SO2 CEMS, a Hg 

CEMS or sorbent trap monitoring 

system, an HCl or HF CEMS, and any 

supporting monitors for such systems 

(such as a diluent or moisture monitor) 

shall be submitted using the ECMPS 

Client Tool, as provided for in 

Appendices A and B to this subpart and 

§ 63.10021(f). 

(4) Submit the compliance reports 

required under paragraphs (c) and (d) of 

this section and the notification of 

compliance status required under 

§ 63.10030(e) to EPA’s WebFIRE 

database by using the Compliance and 

Emissions Data Reporting Interface 

(CEDRI) that is accessed through EPA’s 

Central Data Exchange (CDX) 

(www.epa.gov/cdx). You must use the 

appropriate electronic reporting form in 

CEDRI or provide an alternate electronic 

file consistent with EPA’s reporting 

form output format. 

(5) All reports required by this 

subpart not subject to the requirements 

in paragraphs (f)(1) through (4) of this 

section must be sent to the 

Administrator at the appropriate 

address listed in § 63.13. If acceptable to 

both the Administrator and the owner or 

operator of a source, these reports may 

be submitted on electronic media. The 

Administrator retains the right to 

require submittal of reports subject to 

paragraphs (f)(1), (2), and (3) of this 

section in paper format. 

(g) If you had a malfunction during 

the reporting period, the compliance 

report must include the number, 

duration, and a brief description for 

each type of malfunction which 

occurred during the reporting period 

and which caused or may have caused 

any applicable emission limitation to be 

exceeded. 

§ 63.10032 What records must I keep? 

(a) You must keep records according 

to paragraphs (a)(1) and (2) of this 

section. If you are required to (or elect 

to) continuously monitor Hg and/or HCl 

and/or HF emissions, you must also 

keep the records required under 

appendix A and/or appendix B to this 

subpart. 

(1) A copy of each notification and 

report that you submitted to comply 

with this subpart, including all 

documentation supporting any Initial 

Notification or Notification of 

Compliance Status or semiannual 

compliance report that you submitted, 

according to the requirements in 

§ 63.10(b)(2)(xiv). 

(2) Records of performance stack tests, 

fuel analyses, or other compliance 

demonstrations and performance 

evaluations, as required in 

§ 63.10(b)(2)(viii). 

(b) For each CEMS and CPMS, you 

must keep records according to 

paragraphs (b)(1) through (4) of this 

section. 

(1) Records described in 

§ 63.10(b)(2)(vi) through (xi). 

(2) Previous (i.e., superseded) 

versions of the performance evaluation 

plan as required in § 63.8(d)(3). 

(3) Request for alternatives to relative 

accuracy test for CEMS as required in 

§ 63.8(f)(6)(i). 

(4) Records of the date and time that 

each deviation started and stopped, and 

whether the deviation occurred during a 

period of startup, shutdown, or 

malfunction or during another period. 

(c) You must keep the records 

required in Table 7 to this subpart 

including records of all monitoring data 

and calculated averages for applicable 

PM CPMS operating limits to show 

continuous compliance with each 

emission limit and operating limit that 

applies to you. 

(d) For each EGU subject to an 

emission limit, you must also keep the 

records in paragraphs (d)(1) through (3) 

of this section. 

(1) You must keep records of monthly 

fuel use by each EGU, including the 

type(s) of fuel and amount(s) used. 

(2) If you combust non-hazardous 

secondary materials that have been 

determined not to be solid waste 

pursuant to 40 CFR 241.3(b)(1), you 

must keep a record which documents 

how the secondary material meets each 

of the legitimacy criteria. If you combust 

a fuel that has been processed from a 

discarded non-hazardous secondary 

material pursuant to 40 CFR 241.3(b)(2), 

you must keep records as to how the 

operations that produced the fuel 

satisfies the definition of processing in 

40 CFR 241.2. If the fuel received a nonwaste determination pursuant to the 

petition process submitted under 40 

CFR 241.3(c), you must keep a record 

which documents how the fuel satisfies 

the requirements of the petition process. 

(3) For an EGU that qualifies as an 

LEE under § 63.10005(h), you must keep 

annual records that document that your 

emissions in the previous stack test(s) 

continue to qualify the unit for LEE 

status for an applicable pollutant, and 

document that there was no change in 

source operations including fuel 

composition and operation of air 

pollution control equipment that would 

cause emissions of the pollutant to 

increase within the past year. 

(e) If you elect to average emissions 

consistent with § 63.10009, you must 

additionally keep a copy of the 

emissions averaging implementation 


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plan required in § 63.10009(g), all 

calculations required under § 63.10009, 

including daily records of heat input or 

steam generation, as applicable, and 

monitoring records consistent with 

§ 63.10022. 

(f) You must keep records of the 

occurrence and duration of each startup 

and/or shutdown. 

(g) You must keep records of the 

occurrence and duration of each 

malfunction of an operation (i.e., 

process equipment) or the air pollution 

control and monitoring equipment. 

(h) You must keep records of actions 

taken during periods of malfunction to 

minimize emissions in accordance with 

§ 63.10000(b), including corrective 

actions to restore malfunctioning 

process and air pollution control and 

monitoring equipment to its normal or 

usual manner of operation. 

(i) You must keep records of the 

type(s) and amount(s) of fuel used 

during each startup or shutdown. 

(j) If you elect to establish that an EGU 

qualifies as a limited-use liquid oil-fired 

EGU, you must keep records of the 

type(s) and amount(s) of fuel use in each 

calendar quarter to document that the 

capacity factor limitation for that 

subcategory is met. 

§ 63.10033 In what form and how long 

must I keep my records? 

(a) Your records must be in a form 

suitable and readily available for 

expeditious review, according to 

§ 63.10(b)(1). 

(b) As specified in § 63.10(b)(1), you 

must keep each record for 5 years 

following the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record. 

(c) You must keep each record on site 

for at least 2 years after the date of each 

occurrence, measurement, maintenance, 

corrective action, report, or record, 

according to § 63.10(b)(1). You can keep 

the records off site for the remaining 3 

years. 

Other Requirements and Information 

§ 63.10040 What parts of the General 

Provisions apply to me? 

Table 9 to this subpart shows which 

parts of the General Provisions in 

§§ 63.1 through 63.15 apply to you. 

§ 63.10041 Who implements and enforces 

this subpart? 

(a) This subpart can be implemented 

and enforced by U.S. EPA, or a 

delegated authority such as your state, 

local, or tribal agency. If the EPA 

Administrator has delegated authority to 

your state, local, or tribal agency, then 

that agency (as well as the U.S. EPA) has 

the authority to implement and enforce 

this subpart. You should contact your 

EPA Regional Office to find out if this 

subpart is delegated to your state, local, 

or tribal agency. 

(b) In delegating implementation and 

enforcement authority of this subpart to 

a state, local, or tribal agency under 40 

CFR part 63, subpart E, the authorities 

listed in paragraphs (b)(1) through (4) of 

this section are retained by the EPA 

Administrator and are not transferred to 

the state, local, or tribal agency; 

moreover, the U.S. EPA retains 

oversight of this subpart and can take 

enforcement actions, as appropriate, 

with respect to any failure by any 

person to comply with any provision of 

this subpart. 

(1) Approval of alternatives to the 

non-opacity emission limits and work 

practice standards in § 63.9991(a) and 

(b) under § 63.6(g). 

(2) Approval of major change to test 

methods in Table 5 to this subpart 

under § 63.7(e)(2)(ii) and (f) and as 

defined in § 63.90, approval of minor 

and intermediate changes to monitoring 

performance specifications/procedures 

in Table 5 where the monitoring serves 

as the performance test method (see 

definition of ‘‘test method’’ in § 63.2. 

(3) Approval of major changes to 

monitoring under § 63.8(f) and as 

defined in § 63.90. 

(4) Approval of major change to 

recordkeeping and reporting under 

§ 63.10(e) and as defined in § 63.90. 

§ 63.10042 What definitions apply to this 

subpart? 

Terms used in this subpart are 

defined in the Clean Air Act (CAA), in 

§ 63.2 (the General Provisions), and in 

this section as follows: 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

Anthracite coal means solid fossil fuel 

classified as anthracite coal by 

American Society of Testing and 

Materials (ASTM) Method D388–05, 

‘‘Standard Classification of Coals by 

Rank’’ (incorporated by reference, see 

§ 63.14). 

Bituminous coal means coal that is 

classified as bituminous according to 

ASTM Method D388–05, ‘‘Standard 

Classification of Coals by Rank’’ 

(incorporated by reference, see § 63.14). 

Boiler operating day means a 24-hour 

period between midnight and the 

following midnight during which any 

fuel is combusted at any time in the 

steam generating unit. It is not necessary 

for the fuel to be combusted the entire 

24-hour period. 

Capacity factor for a liquid oil-fired 

EGU means the total annual heat input 

from oil divided by the product of 

maximum hourly heat input for the 

EGU, regardless of fuel, multiplied by 

8,760 hours. 

Coal means all solid fuels classifiable 

as anthracite, bituminous, subbituminous, or lignite by ASTM Method 

D388–05, ‘‘Standard Classification of 

Coals by Rank’’ (incorporated by 

reference, see § 63.14), and coal refuse. 

Synthetic fuels derived from coal for the 

purpose of creating useful heat 

including but not limited to, coal 

derived gases (not meeting the 

definition of natural gas), solventrefined coal, coal-oil mixtures, and coalwater 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 for more than 10.0 percent of 

the average annual heat input during 

any 3 consecutive calendar years or for 

more than 15.0 percent of the annual 

heat input during any one calendar year. 

Coal refuse means any by-product of 

coal mining, physical coal cleaning, and 

coal preparation operations (e.g., culm, 

gob, etc.) containing coal, matrix 

material, clay, and other organic and 

inorganic material with an ash content 

greater than 50 percent (by weight) and 

a heating value less than 13,900 

kilojoules per kilogram (6,000 Btu per 

pound) on a dry basis. 

Cogeneration means a steamgenerating 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 


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of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle 

cogeneration unit, useful power not less 

than 45 percent of total energy input. 

(3) Provided that the total energy 

input under paragraphs (2)(i)(B) and 

(2)(ii) of this definition shall equal the 

unit’s total energy input from all fuel 

except biomass if the unit is a boiler. 

Combined-cycle gas stationary 

combustion turbine means a stationary 

combustion turbine system where heat 

from the turbine exhaust gases is 

recovered by a waste heat boiler. 

Common stack means the exhaust of 

emissions from two or more affected 

units through a single flue. 

Continental liquid oil-fired 

subcategory means any oil-fired electric 

utility steam generating unit that burns 

liquid oil and 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. 

(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 D396–10, ‘‘Standard 

Specification for Fuel Oils’’ 

(incorporated by reference, see § 63.14). 

Dry flue gas desulfurization 

technology, or dry FGD, or spray dryer 

absorber (SDA), or spray dryer, or dry 

scrubber means an add-on air pollution 

control system located downstream of 

the steam generating unit that injects a 

dry alkaline sorbent (dry sorbent 

injection) or sprays an alkaline sorbent 

slurry (spray dryer) to react with and 

neutralize acid gases such as SO2 and 

HCl in the exhaust stream forming a dry 

powder material. Alkaline sorbent 

injection systems in fluidized bed 

combustors (FBC) or circulating 

fluidized bed (CFB) boilers are included 

in this definition. 

Dry sorbent injection (DSI) means an 

add-on air pollution control system in 

which sorbent (e.g., conventional 

activated carbon, brominated activated 

carbon, Trona, hydrated lime, sodium 

carbonate, etc.) is injected into the flue 

gas steam upstream of a PM control 

device to react with and neutralize acid 

gases (such as SO2 and HCl) or Hg in the 

exhaust stream forming a dry powder 

material that may be removed in a 

primary or secondary PM control 

device. 

Electric Steam generating unit means 

any furnace, boiler, or other device used 

for combusting fuel for the purpose of 

producing steam (including fossil-fuelfired steam generators associated with 

integrated gasification combined cycle 

gas turbines; nuclear steam generators 

are not included) for the purpose of 

powering a generator to produce 

electricity or electricity and other 

thermal energy. 

Electric utility steam generating unit 

(EGU) means a fossil fuel-fired 

combustion unit of more than 25 

megawatts electric (MWe) that serves a 

generator that produces electricity for 

sale. A fossil fuel-fired unit that 

cogenerates steam and electricity and 

supplies more than one-third of its 

potential electric output capacity and 

more than 25 MWe output to any utility 

power distribution system for sale is 

considered an electric utility steam 

generating unit. 

Emission limitation means any 

emissions limit, work practice standard, 

or operating limit. 

Excess emissions means, with respect 

to this subpart, results of any required 

measurements outside the applicable 

range (e.g., emissions limitations, 

parametric operating limits) that is 

permitted by this subpart. The values of 

measurements will be in the same units 

and averaging time as the values 

specified in this subpart for the 

limitations. 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the Administrator, 

including the requirements of 40 CFR 

parts 60, 61, and 63; requirements 

within any applicable state 

implementation plan; and any permit 

requirements established under 40 CFR 

52.21 or under 40 CFR 51.18 and 40 

CFR 51.24. 

Flue gas desulfurization system 

means any add-on air pollution control 

system located downstream of the steam 

generating unit whose purpose or effect 

is to remove at least 50 percent of the 

SO2 in the exhaust gas stream. 

Fossil fuel means natural gas, oil, 

coal, and any form of solid, liquid, or 

gaseous fuel derived from such material. 

Fossil fuel-fired means an electric 

utility steam generating unit (EGU) that 

is capable of combusting more than 25 

MW of fossil fuels. To be ‘‘capable of 

combusting’’ fossil fuels, an EGU would 

need to have these fuels allowed in its 

operating permit and have the 

appropriate fuel handling facilities 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 during any 3 consecutive calendar 

years or for more than 15.0 percent of 

the annual heat input during any one 

calendar year after the applicable 

compliance date. 

Fuel type means each category of fuels 

that share a common name or 

classification. Examples include, but are 

not limited to, bituminous coal, 

subbituminous coal, lignite, anthracite, 

biomass, and residual oil. Individual 

fuel types received from different 

suppliers are not considered new fuel 

types. 

Fluidized bed boiler, or fluidized bed 

combustor, or circulating fluidized 

boiler, or CFB means a boiler utilizing 

a fluidized bed combustion process. 

Fluidized bed combustion means a 

process where a fuel is burned in a bed 

of granulated particles which are 

maintained in a mobile suspension by 

the upward flow of air and combustion 

products. 

Gaseous fuel includes, but is not 

limited to, natural gas, process gas, 

landfill gas, coal derived gas, solid oilderived gas, refinery gas, and biogas. 

Generator means a device that 

produces electricity. 

Gross output means the gross useful 

work performed by the steam generated 

and, for an IGCC electric utility steam 

generating unit, the work performed by 

the stationary combustion turbines. For 

a unit generating only electricity, the 

gross useful work performed is the gross 

electrical output from the unit’s turbine/ 

generator sets. For a cogeneration unit, 

the gross useful work performed is the 

gross electrical output, including any 

such electricity used in the power 

production process (which process 

includes, but is not limited to, any onsite 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 


srobinson on DSK4SPTVN1PROD with RULES2
9486 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

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 oil-derived 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 combinedcycle gas turbine. No solid coal or solid 

oil-derived fuel is directly burned in the 

unit during operation. 

ISO conditions means a temperature 

of 288 Kelvin, a relative humidity of 60 

percent, and a pressure of 101.3 

kilopascals. 

Lignite coal means coal that is 

classified as lignite A or B according to 

ASTM Method D388–05, ‘‘Standard 

Classification of Coals by Rank’’ 

(incorporated by reference, see § 63.14). 

Limited-use liquid oil-fired 

subcategory means an oil-fired electric 

utility steam generating unit with an 

annual capacity factor of less than 8 

percent of its maximum or nameplate 

heat input, whichever is greater, 

averaged over a 24-month block 

contiguous period commencing April 

16, 2015. 

Liquid fuel includes, but is not 

limited to, distillate oil and residual oil. 

Monitoring system malfunction or out 

of control period means any sudden, 

infrequent, not reasonably preventable 

failure of the monitoring system to 

provide valid data. Monitoring system 

failures that are caused in part by poor 

maintenance or careless operation are 

not malfunctions. 

Natural gas means a naturally 

occurring fluid mixture of hydrocarbons 

(e.g., methane, ethane, or propane) 

produced in geological formations 

beneath the Earth’s surface that 

maintains a gaseous state at standard 

atmospheric temperature and pressure 

under ordinary conditions. Natural gas 

contains 20.0 grains or less of total 

sulfur per 100 standard cubic feet. 

Additionally, natural gas must either be 

composed of at least 70 percent methane 

by volume or have a gross calorific 

value between 950 and 1,100 Btu per 

standard cubic foot. Natural gas does 

not include the following gaseous fuels: 

landfill gas, digester gas, refinery gas, 

sour gas, blast furnace gas, coal-derived 

gas, producer gas, coke oven gas, or any 

gaseous fuel produced in a process 

which might result in highly variable 

sulfur content or heating value. 

Natural gas-fired electric utility steam 

generating unit means an electric utility 

steam generating unit meeting the 

definition of ‘‘fossil fuel-fired’’ that is 

not a coal-fired, oil-fired, or IGCC 

electric utility steam generating unit and 

that burns natural gas for more than 10.0 

percent of the average annual heat input 

during any 3 consecutive calendar years 

or for more than 15.0 percent of the 

annual heat input during any one 

calendar year. 

Net-electric output means the gross 

electric sales to the utility power 

distribution system minus purchased 

power on a calendar year basis. 

Non-continental area means the State 

of Hawaii, the Virgin Islands, Guam, 

American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana 

Islands. 

Non-continental liquid oil-fired 

subcategory means any oil-fired electric 

utility steam generating unit that burns 

liquid oil and is located outside the 

continental United States. 

Non-mercury (Hg) HAP metals means 

Antimony (Sb), Arsenic (As), Beryllium 

(Be), Cadmium (Cd), Chromium (Cr), 

Cobalt (Co), Lead (Pb), Manganese (Mn), 

Nickel (Ni), and Selenium (Se). Oil 

means crude oil or petroleum or a fuel 

derived from crude oil or petroleum, 

including distillate and residual oil, 

solid oil-derived fuel (e.g., petroleum 

coke) and gases derived from solid oilderived fuels (not meeting the definition 

of natural gas). 

Oil-fired electric utility steam 

generating unit means an electric utility 

steam generating unit meeting the 

definition of ‘‘fossil fuel-fired’’ that is 

not a coal-fired electric utility steam 

generating unit and that burns oil for 

more than 10.0 percent of the average 

annual heat input during any 3 

consecutive calendar years or for more 

than 15.0 percent of the annual heat 

input during any one calendar year. 

Particulate matter or PM means any 

finely divided solid material as 

measured by the test methods specified 

under this subpart, or an alternative 

method. 

Pulverized coal (PC) boiler means an 

EGU in which pulverized coal is 

introduced into an air stream that 

carries the coal to the combustion 

chamber of the EGU where it is fired in 

suspension. 

Residual oil means crude oil, and all 

fuel oil numbers 4, 5 and 6, as defined 

by ASTM Method D396–10, ‘‘Standard 

Specification for Fuel Oils’’ 

(incorporated by reference, see § 63.14). 

Responsible official means 

responsible official as defined in 40 CFR 

70.2. 

Shutdown means the cessation of 

operation of a boiler for any purpose. 

Shutdown begins either when none of 

the steam from the boiler is used to 

generate electricity for sale over the grid 

or for any other purpose (including onsite use), or at the point of no fuel being 

fired in the boiler, whichever is earlier. 

Shutdown ends when there is both no 

electricity being generated and no fuel 

being fired in the boiler. 

Startup means either the first-ever 

firing of fuel in a boiler for the purpose 

of producing electricity, or the firing of 

fuel in a boiler after a shutdown event 

for any purpose. Startup ends when any 

of the steam from the boiler is used to 

generate electricity for sale over the grid 

or for any other purpose (including onsite use). 

Stationary combustion turbine means 

all equipment, including but not limited 

to the turbine, the fuel, air, lubrication 

and exhaust gas systems, control 

systems (except emissions control 

equipment), and any ancillary 

components and sub-components 

comprising any simple cycle stationary 

combustion turbine, any regenerative/ 

recuperative cycle stationary 

combustion turbine, the combustion 

turbine portion of any stationary 

cogeneration cycle combustion system, 

or the combustion turbine portion of 

any stationary combined cycle steam/ 

electric generating system. Stationary 

means that the combustion turbine is 

not self 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-fuelfired steam generators associated with 

integrated gasification combined cycle 

gas turbines; nuclear steam generators 

are not included). 

Stoker means a unit consisting of a 

mechanically operated fuel feeding 

mechanism, a stationary or moving grate 

to support the burning of fuel and admit 

undergrate air to the fuel, an overfire air 

system to complete combustion, and an 

ash discharge system. There are two 

general types of stokers: underfeed and 


srobinson on DSK4SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9487 

overfeed. Overfeed stokers include mass 

feed and spreader stokers. 

Subbituminous coal means coal that 

is classified as subbituminous A, B, or 

C according to ASTM Method D388–05, 

‘‘Standard Classification of Coals by 

Rank’’ (incorporated by reference, see 

§ 63.14). 

Unit designed for coal > 8,300 Btu/lb 

subcategory means any coal-fired EGU 

that is not a coal-fired EGU in the ‘‘unit 

designed for low rank virgin coal’’ 

subcategory. 

Unit designed for low rank virgin coal 

subcategory means any coal-fired EGU 

that is designed to burn and that is 

burning nonagglomerating virgin coal 

having a calorific value (moist, mineral 

matter-free basis) of less than 19,305 kJ/ 

kg (8,300 Btu/lb) that is constructed and 

operates at or near the mine that 

produces such coal. 

Unit designed to burn solid oilderived fuel subcategory means any oilfired EGU that burns solid oil-derived 

fuel. 

Voluntary consensus standards or 

VCS mean technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, business 

practices) developed or adopted by one 

or more voluntary consensus bodies. 

The EPA/OAQPS has by precedent only 

used VCS that are written in English. 

Examples of VCS bodies are: American 

Society of Testing and Materials 

(ASTM), American Society of 

Mechanical Engineers (ASME), 

International Standards Organization 

(ISO), Standards Australia (AS), British 

Standards (BS), Canadian Standards 

(CSA), European Standard (EN or CEN) 

and German Engineering Standards 

(VDI). The types of standards that are 

not considered VCS are standards 

developed by: the U.S. states, e.g., 

California (CARB) and Texas (TCEQ); 

industry groups, such as American 

Petroleum Institute (API), Gas 

Processors Association (GPA), and Gas 

Research Institute (GRI); and other 

branches of the U.S. government, e.g., 

Department of Defense (DOD) and 

Department of Transportation (DOT). 

This does not preclude EPA from using 

standards developed by groups that are 

not VCS bodies within an EPA rule. 

When this occurs, EPA has done 

searches and reviews for VCS equivalent 

to these non-VCS methods. 

Wet flue gas desulfurization 

technology, or wet FGD, or wet scrubber 

means any add-on air pollution control 

device that is located downstream of the 

steam generating unit that mixes an 

aqueous stream or slurry with the 

exhaust gases from an EGU to control 

emissions of PM and/or to absorb and 

neutralize acid gases, such as SO2 and 

HCl. 

Work practice standard means any 

design, equipment, work practice, or 

operational standard, or combination 

thereof, which is promulgated pursuant 

to CAA section 112(h). 

Tables to Subpart UUUUU of Part 63 

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS

[As stated in § 63.9991, you must comply with the following applicable emission limits] 

If your EGU is in this 

subcategory . . . For the following pollutants . . . 

You must meet the following 

emission limits and work practice 

standards . . . 

Using these requirements, as appropriate (e.g., specified sampling 

volume or test run duration) and 

limitations with the test methods 

in Table . . . 

1. Coal-fired unit not low rank virgin coal.a. Filterable particulate matter 

(PM).

7.0E–3 lb/MWh1 ............................ Collect a minimum of 4 dscm per 

run. 

OR OR 

Total non-Hg HAP metals 6.0E–2 lb/GWh ............................. Collect a minimum of 4 dscm per 

run. 

OR OR 

individual HAP metals: ................. Collect a minimum of 3 dscm per 

run. 

Antimony (Sb) ............................... 8.0E–3 lb/GW. 

Arsenic (As) .................................. 3.0E–3 lb/GWh. 

Beryllium (Be) ............................... 6.0E–4 lb/GWh. 

Cadmium (Cd) .............................. 4.0E–4 lb/GWh. 

Chromium (Cr) .............................. 7.0E–3 lb/GWh. 

Cobalt (Co) ................................... 2.0E–3 lb/GWh. 

Lead (Pb) ...................................... 2.0E–3 lb/GWh. 

Manganese (Mn) .......................... 4.0E–3 lb/GWh. 

Nickel (Ni) ..................................... 4.0E–2 lb/GWh. 

Selenium (Se) ............................... 6.0E–3 lb/GWh. 

b. Hydrogen chloride (HC1) ......... 4.0E–4 lb/MWh ............................. For Method 26A, collect a minimum of 3 dscm per run. 

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

OR. 

Sulfur dioxide (SO2) 3 .................... 4.0E–1 lb/MWh ............................. SO2 CEMS. 

c. Mercury (Hg) ............................. 2.0E–4 lb/GWh ............................. Hg CEMS or sorbent trap monitoring system only. 

2. Coal-fired units low rank virgin 

coal.

a. Filterable particulate matter 

(PM).

7.0E–3 lb/MWh1 ............................ Collect a minimum of 4 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............ 6.0E–2 lb/GWh ............................. Collect a minimum of 4 dscm per 

run. 

OR OR 

Individual HAP metals: .................................................. Collect a minimum of 3 dscm per 

run. 

Antimony (Sb) ............................... 8.0E–3 lb/GWh. 

Arsenic (As) .................................. 3.0E–3 lb/GWh. 


srobinson on DSK4SPTVN1PROD with RULES2
9488 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued 

[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) and 

limitations with the test methods 

in Table . . . 

Beryllium (Be) ............................... 6.0E–4 lb/GWh. 

Cadmium (Cd) .............................. 4.0E–4 lb/GWh. 

Chromium (Cr) .............................. 7.0E–3 lb/GWh. 

Cobalt (Co) ................................... 2.0E–3 lb/GWh. 

Lead (Pb) ...................................... 2.0E–3 lb/GWh. 

Manganese (Mn) .......................... 4.0E–3 lb/GWh. 

Nickel (Ni) ..................................... 4.0E–2 lb/GWh. 

Selenium (Se) ............................... 6.0E–3 lb/GWh. 

b. Hydrogen chloride (HCl) ........... 4.0E–4 lb/MWh ............................. For Method 26A, collect a minimum of 3 dscm per run. 

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

OR 

Sulfur dioxide (SO2) 3 .................... 4.0E–1 lb/MWh ............................. SO2 CEMS. 

c. Mercury (Hg) ............................. 4.0E–2 lb/GWh ............................. Hg CEMS or sorbent trap monitoring system only. 

3. IGCC unit ................................... a. Filterable particulate matter 

(PM).

7.0E–2 lb/MWh 4 ...........................

9.0E–2 lb/MWh 5

Collect a minimum of 1 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............ 4.0E–1 lb/GWh ............................. Collect a minimum of 1 dscm per 

run. 

OR OR 

Individual HAP metals: ....................................................... Collect a minimum of 2 dscm per 

run. 

Antimony (Sb) ............................... 2.0E–2 lb/GWh. 

Arsenic (As) .................................. 2.0E–2 lb/GWh. 

Beryllium (Be) ............................... 1.0E–3 lb/GWh. 

Cadmium (Cd) .............................. 2.0E–3 lb/GWh. 

Chromium (Cr) .............................. 4.0E–2 lb/GWh. 

Cobalt (Co) ................................... 4.0E–3 lb/GWh. 

Lead (Pb) ...................................... 9.0E–3 lb/GWh. 

Manganese (Mn) .......................... 2.0E–2 lb/GWh. 

Nickel (Ni) ..................................... 7.0E–2 lb/GWh. 

Selenium (Se) ............................... 3.0E–1 lb/GWh. 

b. Hydrogen chloride (HCl) ........... 2.0E–3 lb/MWh ............................. For Method 26A, collect a minimum of 1 dscm per run; for 

Method 26, collect a minimum 

of 120 liters per run. 

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

OR 

Sulfur dioxide (SO2) 3 4.0E–1 lb/MWh ............................. SO2 CEMS. 

c. Mercury (Hg) ............................. 3.0E–3 lb/GWh ............................. Hg CEMS or sorbent trap monitoring system only. 

4. Liquid oil-fired unit—continental 

(excluding limited-use liquid oilfired subcategory units).

a. Filterable particulate matter 

(PM).

7.0E–2 lb/MWh1 ............................ Collect a minimum of 1 dscm per 

run. 

OR OR 

Total HAP metals ......................... 2.0E–4 lb/MWh ............................. Collect a minimum of 2 dscm per 

run. 

OR OR 

Individual HAP metals: ....................................................... Collect a minimum of 2 dscm per 

run. 

Antimony (Sb) ............................... 1.0E–2 lb/GWh. 

Arsenic (As) .................................. 3.0E–3 lb/GWh. 

Beryllium (Be) ............................... 5.0E–4 lb/GWh. 

Cadmium (Cd) .............................. 2.0E–4 lb/GWh. 

Chromium (Cr) .............................. 2.0E–2 lb/GWh. 

Cobalt (Co) ................................... 3.0E–2 lb/GWh. 

Lead (Pb) ...................................... 8.0E–3 lb/GWh. 

Manganese (Mn) .......................... 2.0E–2 lb/GWh. 

Nickel (Ni) ..................................... 9.0E–2 lb/GWh. 

Selenium (Se) ............................... 2.0E–2 lb/GWh. 


srobinson on DSK4SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9489 

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued 

[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) and 

limitations with the test methods 

in Table . . . 

Mercury (Hg) 1.0E–4 lb/GWh ............................. For Method 30B sample volume 

determination (Section 8.2.4), 

the estimated Hg concentration 

should nominally be <1⁄2 the 

standard. 

b. Hydrogen chloride (HCl) 4.0E–4 lb/MWh ............................. For Method 26A, collect a minimum of 3 dscm per run. 

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

c. Hydrogen fluoride (HF) 4.0E–4 lb/MWh ............................. For Method 26A, collect a minimum of 3 dscm per run. 

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

5. Liquid oil-fired unit—non-continental (excluding limited-use liquid oil-fired subcategory units).a. Filterable particulate matter 

(PM).

2.0E–1 lb/MWh1 ............................ Collect a minimum of 1 dscm per 

run. 

OR OR 

Total HAP metals 7.0E–3 lb/MWh ............................. Collect a minimum of 1 dscm per 

run. 

OR OR 

Individual HAP metals: ....................................................... Collect a minimum of 3 dscm per 

run. 

Antimony (Sb) ............................... 8.0E–3 lb/GWh. 

Arsenic (As) .................................. 6.0E–2 lb/GWh. 

Beryllium (Be) ............................... 2.0E–3 lb/GWh. 

Cadmium (Cd) .............................. 2.0E–3 lb/GWh. 

Chromium (Cr) .............................. 2.0E–2 lb/GWh. 

Cobalt (Co) ................................... 3.0E–1 lb/GWh. 

Lead (Pb) ...................................... 3.0E–2 lb/GWh. 

Manganese (Mn) .......................... 1.0E–1 lb/GWh. 

Nickel (Ni) ..................................... 4.1E–0 lb/GWh. 

Selenium (Se) ............................... 2.0E–2 lb/GWh. 

Mercury (Hg) ................................. 4.0E–4 lb/GWh ............................. For Method 30B sample volume 

determination (Section 8.2.4), 

the estimated Hg concentration 

should nominally be < 1⁄2 the 

standard. 

b. Hydrogen chloride (HCl) 2.0E–3 lb/MWh ............................. For Method 26A, collect a minimum of 1 dscm per run; for 

Method 26, collect a minimum 

of 120 liters per run. 

For ASTM D6348–032 or Method 

320, sample for a minimum of 1 

hour 

c. Hydrogen fluoride (HF) 5.0E–4 lb/MWh ............................. For Method 26A, collect a minimum of 3 dscm per run. 

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

6. Solid oil-derived fuel-fired unit ... a. Filterable particulate matter 

(PM).

2.0E–2 lb/MWh1 ............................ Collect a minimum of 1 dscm per 

run. 

OR OR 

Total non-Hg HAP metals 6.0E–1 lb/GWh ............................. Collect a minimum of 1 dscm per 

run. 

OR OR 

Individual HAP metals: ....................................................... Collect a minimum of 3 dscm per 

run. 

Antimony (Sb) ............................... 8.0E–3 lb/GWh. 

Arsenic (As) .................................. 3.0E–3 lb/GWh. 

Beryllium (Be) ............................... 6.0E–4 lb/GWh. 

Cadmium (Cd) .............................. 7.0E–4 lb/GWh. 

Chromium (Cr) .............................. 6.0E–3 lb/GWh. 

Cobalt (Co) ................................... 2.0E–3 lb/GWh. 


srobinson on DSK4SPTVN1PROD with RULES2
9490 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued 

[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) and 

limitations with the test methods 

in Table . . . 

Lead (Pb) ...................................... 2.0E–2 lb/GWh. 

Manganese (Mn) .......................... 7.0E–3 lb/GWh. 

Nickel (Ni) ..................................... 4.0E–2 lb/GWh. 

Selenium (Se) ............................... 6.0E–3 lb/GWh. 

b. Hydrogen chloride (HCl) ........... 4.0E–4 lb/MWh ............................. For Method 26A, collect a minimum of 3 dscm per run. 

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

OR 

Sulfur dioxide (SO2) 3 .................... 4.0E–1 lb/MWh ............................. SO2 CEMS. 

c. Mercury (Hg) ............................. 2.0E–3 lb/GWh ............................. Hg CEMS or Sorbent trap monitoring system only. 

1Gross electric output. 

2 Incorporated by reference, see § 63.14. 

3You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS installed. 4 Duct burners on syngas; gross electric output. 

5 Duct burners on natural gas; gross electric output 

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS

[As stated in § 63.9991, you must comply with the following applicable emission limits] 1

If your EGU is in this subcategory For the following pollutants 

You must meet the following 

emission limits and work practice 

standards 

Using these requirements, as appropriate (e.g., specified sampling 

volume or test run duration) and 

limitations with the test methods in 

Table 5 

1. Coal-fired unit not low rank virgin coal.a. Filterable particulate matter 

(PM).

3.0E–2 lb/MMBtu or 3.0E–1 lb/ 

MWh 2.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............. 5.0E–5 lb/MMBtu or 5.0E–1 lb/ 

GWh.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Individual HAP metals 

Antimony (Sb) ............................... 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.

Arsenic (As) .................................. 1.1E0 lb/TBtu or 2.0E–2 lb/GWh.

Beryllium (Be) ............................... 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh.

Cadmium (Cd) ............................... 3.0E–1 lb/TBtu or 3.0E–3 lb/GWh.

Chromium (Cr) .............................. 2.8E0 lb/TBtu or 3.0E–2 lb/GWh.

Cobalt (Co) .................................... 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.

Lead (Pb) ...................................... 1.2E0 lb/TBtu or 2.0E–2 lb/GWh.

Manganese (Mn) ........................... 4.0E0 lb/TBtu or 5.0E–2 lb/GWh.

Nickel (Ni) ..................................... 3.5E0 lb/TBtu or 4.0E–2 lb/GWh.

Selenium (Se) ............................... 5.0E0 lb/TBtu or 6.0E–2 lb/GWh.

b. Hydrogen chloride (HCl) ........... 2.0E–3 lb/MMBtu or 2.0E–2 lb/ 

MWh.

For Method 26A, collect a minimum of 0.75 dscm per run; for 

Method 26, collect a minimum 

of 120 liters per run. 

For ASTM D6348–03 3 or Method 

320, sample for a minimum of 1 

hour. 

OR 

Sulfur dioxide (SO2) 4 .................... 2.0E–1 lb/MMBtu or 1.5E0 lb/ 

MWh.

SO2 CEMS. 

c. Mercury (Hg) ............................. 1.2E0 lb/TBtu or 1.3E–2 lb/GWh .. LEE Testing for 30 days with 10 

days maximum per Method 30B 

run or Hg CEMS or sorbent trap 

monitoring system only. 

2. Coal-fired unit low rank virgin 

coal.

a. Filterable particulate matter 

(PM).

3.0E–2 lb/MMBtu or 3.0E–1 lb/ 

MWh2.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............. 5.0E–5 lb/MMBtu or 5.0E–1 lb/ 

GWh.

Collect a minimum of 1 dscm per 

run. 

OR OR 


srobinson on DSK4SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9491 

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued 

[As stated in § 63.9991, you must comply with the following applicable emission limits] 1

If your EGU is in this subcategory For the following pollutants 

You must meet the following 

emission limits and work practice 

standards 

Using these requirements, as appropriate (e.g., specified sampling 

volume or test run duration) and 

limitations with the test methods in 

Table 5 

Individual HAP metals: ....................................................... Collect a minimum of 3 dscm per 

run. 

Antimony (Sb) ............................... 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.

Arsenic (As) .................................. 1.1E0 lb/TBtu or 2.0E–2 lb/GWh.

Beryllium (Be) ............................... 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh.

Cadmium (Cd) ............................... 3.0E–1 lb/TBtu or 3.0E–3 lb/GWh.

Chromium (Cr) .............................. 2.8E0 lb/TBtu or 3.0E–2 lb/GWh.

Cobalt (Co) .................................... 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.

Lead (Pb) ...................................... 1.2E0 lb/TBtu or 2.0E–2 lb/GWh.

Manganese (Mn) ........................... 4.0E0 lb/TBtu or 5.0E–2 lb/GWh.

Nickel (Ni) ..................................... 3.5E0 lb/TBtu or 4.0E–2 lb/GWh.

Selenium (Se) ............................... 5.0E0 lb/TBtu or 6.0E–2 lb/GWh.

b. Hydrogen chloride (HCl) ........... 2.0E–3 lb/MMBtu or 2.0E–2 lb/ 

MWh.

For Method 26A, collect a minimum of 0.75 dscm per run; for 

Method 26, collect a minimum 

of 120 liters per run. 

For ASTM D6348–03 3 or Method 

320, sample for a minimum of 1 

hour. 

OR 

Sulfur dioxide (SO2) 4 .................... 2.0E–1 lb/MMBtu or 1.5E0 lb/ 

MWh.

SO2 CEMS. 

c. Mercury (Hg) ............................. 4.0E0 lb/TBtu or 4.0E–2 lb/GWh .. LEE Testing for 30 days with 10 

days maximum per Method 30B 

run or Hg CEMS or sorbent trap 

monitoring system only. 

3. IGCC unit .................................. a. Filterable particulate matter 

(PM).

4.0E–2 lb/MMBtu or 4.0E–1 lb/ 

MWh2.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............. 6.0E–5 lb/MMBtu or 5.0E–1 lb/ 

GWh.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Individual HAP metals: .................. ....................................................... Collect a minimum of 2 dscm per 

run. 

Antimony (Sb) ............................... 1.4E0 lb/TBtu or 2.0E–2 lb/GWh.

Arsenic (As) .................................. 1.5E0 lb/TBtu or 2.0E–2 lb/GWh.

Beryllium (Be) ............................... 1.0E–1 lb/TBtu or 1.0E–3 lb/GWh.

Cadmium (Cd) ............................... 1.5E–1 lb/TBtu or 2.0E–3 lb/GWh.

Chromium (Cr) .............................. 2.9E0 lb/TBtu or 3.0E–2 lb/GWh.

Cobalt (Co) .................................... 1.2E0 lb/TBtu or 2.0E–2 lb/GWh.

Lead (Pb) ...................................... 1.9E+2 lb/MMBtu or 1.8E0 lb/ 

MWh.

Manganese (Mn) ........................... 2.5E0 lb/TBtu or 3.0E–2 lb/GWh.

Nickel (Ni) ..................................... 6.5E0 lb/TBtu or 7.0E–2 lb/GWh.

Selenium (Se) ............................... 2.2E+1 lb/TBtu or 3.0E–1 lb/GWh.

b. Hydrogen chloride (HCl) ........... 5.0E–4 lb/MMBtu or 5.0E–3 lb/ 

MWh.

For Method 26A, collect a minimum of 1 dscm per 

run; for Method 26, collect a minimum of 120 liters per run. 

For ASTM D6348–03 3 or Method 

320, sample for a minimum of 1 

hour. 

c. Mercury (Hg) ............................. 2.5E0 lb/TBtu or 3.0E–2 lb/GWh .. LEE Testing for 30 days with 10 

days maximum per Method 30B 

run or Hg CEMS or sorbent trap 

monitoring system only. 

4. Liquid oil-fired unit—continental 

(excluding limited-use liquid oilfired subcategory units).

a. Filterable particulate matter 

(PM).

3.0E–2 lb/MMBtu or 3.0E–1 lb/ 

MWh2.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Total HAP metals .......................... 8.0E–4 lb/MMBtu or 8.0E–3 lb/ 

MWh.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Individual HAP metals ................... Collect a minimum of 1 dscm per 

run. 


srobinson on DSK4SPTVN1PROD with RULES2
9492 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued 

[As stated in § 63.9991, you must comply with the following applicable emission limits] 1

If your EGU is in this subcategory For the following pollutants 

You must meet the following 

emission limits and work practice 

standards 

Using these requirements, as appropriate (e.g., specified sampling 

volume or test run duration) and 

limitations with the test methods in 

Table 5 

Antimony (Sb) ............................... 1.3E+1 lb/TBtu or 2.0E–1 lb/GWh.

Arsenic (As) .................................. 2.8E0 lb/TBtu or 3.0E–2 lb/GWh.

Beryllium (Be) ............................... 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh.

Cadmium (Cd) ............................... 3.0E–1 lb/TBtu or 2.0E–3 lb/GWh.

Chromium (Cr) .............................. 5.5E0 lb/TBtu or 6.0E–2 lb/GWh.

Cobalt (Co) .................................... 2.1E+1 lb/TBtu or 3.0E–1 lb/GWh.

Lead (Pb) ...................................... 8.1E0 lb/TBtu or 8.0E–2 lb/GWh.

Manganese (Mn) ........................... 2.2E+1 lb/TBtu or 3.0E–1 lb/GWh.

Nickel (Ni) ..................................... 1.1E+2 lb/TBtu or 1.1E0 lb/GWh.

Selenium (Se) ............................... 3.3E0 lb/TBtu or 4.0E–2 lb/GWh.

Mercury (Hg) ................................. 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh For Method 30B sample volume 

determination (Section 8.2.4), 

the estimated Hg concentration 

should nominally be < 1⁄2 the 

standard. 

b. Hydrogen chloride (HCl) ........... 2.0E–3 lb/MMBtu or 1.0E–2 lb/ 

MWh.

For Method 26A, collect a minimum of 1 dscm per 

Run; for Method 26, collect a minimum of 120 liters per run. 

For ASTM D6348–03 3 or Method 

320, sample for a minimum of 1 

hour. 

c. Hydrogen fluoride (HF) ............. 4.0E–4 lb/MMBtu or 4.0E–3 lb/ 

MWh.

For Method 26A, collect a minimum of 1 dscm per run; for 

Method 26, collect a minimum 

of 120 liters per run. 

For ASTM D6348–03 3 or Method 

320, sample for a minimum of 1 

hour. 

5. Liquid oil-fired unit—non-continental (excluding limited-use liquid oil-fired subcategory units).a. Filterable particulate matter 

(PM).

3.0E–2 lb/MMBtu or 3.0E–1 lb/ 

MWh2.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Total HAP metals .......................... 6.0E–4 lb/MMBtu or 7.0E–3 lb/ 

MWh.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Individual HAP metals ................... ....................................................... Collect a minimum of 2 dscm per 

run. 

Antimony (Sb) ............................... 2.2E0 lb/TBtu or 2.0E–2 lb/GWh.

Arsenic (As) .................................. 4.3E0 lb/TBtu or 8.0E–2 lb/GWh.

Beryllium (Be) ............................... 6.0E–1 lb/TBtu or 3.0E–3 lb/GWh.

Cadmium (Cd) ............................... 3.0E–1 lb/TBtu or 3.0E–3 lb/GWh.

Chromium (Cr) .............................. 3.1E+1 lb/TBtu or 3.0E–1 lb/GWh.

Cobalt (Co) .................................... 1.1E+2 lb/TBtu or 1.4E0 lb/GWh.

Lead (Pb) ...................................... 4.9E0 lb/TBtu or 8.0E–2 lb/GWh.

Manganese (Mn) ........................... 2.0E+1 lb/TBtu or 3.0E–1 lb/GWh.

Nickel (Ni) ..................................... 4.7E+2 lb/TBtu or 4.1E0 lb/GWh.

Selenium (Se) ............................... 9.8E0 lb/TBtu or 2.0E–1 lb/GWh.

Mercury (Hg) ................................. 4.0E–2 lb/TBtu or 4.0E–4 lb/GWh For Method 30B sample volume 

determination (Section 8.2.4), 

the estimated Hg concentration 

should nominally be < 1⁄2 the 

standard. 

Hydrogen chloride (HCl) ............... 2.0E–4 lb/MMBtu or 2.0E–3 lb/ 

MWh.

For Method 26A, collect a minimum of 1 dscm per run; for 

Method 26, collect a minimum 

of 120 liters per run. 

For ASTM D6348–03 3 or Method 

320, sample for a minimum of 2 

hours. 

c. Hydrogen fluoride (HF) ............. 6.0E–5 lb/MMBtu or 5.0E–4 lb/ 

MWh.

For Method 26A, collect a minimum of 3 dscm per run. 

For ASTM D6348–03 3 or Method 

320, sample for a minimum of 2 

hours. 


srobinson on DSK4SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9493 

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued 

[As stated in § 63.9991, you must comply with the following applicable emission limits] 1

If your EGU is in this subcategory For the following pollutants 

You must meet the following 

emission limits and work practice 

standards 

Using these requirements, as appropriate (e.g., specified sampling 

volume or test run duration) and 

limitations with the test methods in 

Table 5 

6. Solid oil-derived fuel-fired unit .. a. Filterable particulate matter 

(PM).

8.0E–3 lb/MMBtu or 9.0E–2 lb/ 

MWh2.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............. 4.0E–5 lb/MMBtu or 6.0E–1 lb/ 

GWh.

Collect a minimum of 1 dscm per 

run. 

OR OR 

Individual HAP metals ................... ....................................................... Collect a minimum of 3 dscm per 

run. 

Antimony (Sb) ............................... 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.

Arsenic (As) .................................. 3.0E–1 lb/TBtu or 5.0E–3 lb/GWh.

Beryllium (Be) ............................... 6.0E–2 lb/TBtu or 6.0E–4 lb/GWh.

Cadmium (Cd) ............................... 3.0E–1 lb/TBtu or 4.0E–3 lb/GWh.

Chromium (Cr) .............................. 8.0E–1 lb/TBtu or 2.0E–2 lb/GWh.

Cobalt (Co) .................................... 1.1E0 lb/TBtu or 2.0E–2 lb/GWh.

Lead (Pb) ...................................... 8.0E–1 lb/TBtu or 2.0E–2 lb/GWh.

Manganese (Mn) ........................... 2.3E0 lb/TBtu or 4.0E–2 lb/GWh.

Nickel (Ni) ..................................... 9.0E0 lb/TBtu or 2.0E–1 lb/GWh.

Selenium (Se) ............................... 1.2E0 lb/TBtu 2.0E–2 lb/GWh.

b. Hydrogen chloride (HCl) ........... 5.0E–3 lb/MMBtu or 8.0E–2 lb/ 

MWh.

For Method 26A, collect a minimum of 0.75 dscm per run; for 

Method 26, collect a minimum 

of 120 liters per run. 

For ASTM D6348–03 3 or Method 

320, sample for a minimum of 1 

hour. 

OR 

Sulfur dioxide (SO2) 4 .................... 3.0E–1 lb/MMBtu or 2.0E0 lb/ 

MWh.

SO2 CEMS. 

c. Mercury (Hg) ............................. 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh LEE Testing for 30 days with 10 

days maximum per Method 30B 

run or Hg CEMS or Sorbent 

trap monitoring system only. 

1For 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. 2Gross electric output. 

3 Incorporated by reference, see § 63.14. 

4You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS installed. 

TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS

[As stated in §§ 63.9991, you must comply with the following applicable work practice standards] 

If your EGU is . . . You must meet the following . . . 

1. An existing EGU ............................................. Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar 

months, or each 48 calendar months if neural network combustion optimization software is 

employed, as specified in § 63.10021(e). 

2. A new or reconstructed EGU ......................... Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar 

months, or each 48 calendar months if neural network combustion optimization software is 

employed, as specified in § 63.10021(e). 

3. A coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGU during startup.You must operate all CMS during startup. Startup means either the first-ever firing of fuel in a 

boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown 

event for any purpose. Startup ends when any of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on site use). For 

startup of a unit, you must use clean fuels, either natural gas or distillate oil or a combination of clean fuels for ignition. Once you convert to firing coal, residual oil, or solid oil-derived fuel, you must engage all of the applicable control technologies except dry scrubber 

and SCR. You must start your dry scrubber and SCR systems, if present, appropriately to 

comply with relevant standards applicable during normal operation. You must comply with all 

applicable emissions limits at all times except for periods that meet the definitions of startup 

and shutdown in this subpart. You must keep records during periods of startup. You must 

provide reports concerning activities and periods of startup, as specified in § 63.10011(g) 

and § 63.10021(h) and (i). 


srobinson on DSK4SPTVN1PROD with RULES2
9494 Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 

TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS—Continued 

[As stated in §§ 63.9991, you must comply with the following applicable work practice standards] 

If your EGU is . . . You must meet the following . . . 

4. A coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGU during shutdown.You must operate all CMS during shutdown. Shutdown means the cessation of operation of a 

boiler for any purpose. Shutdown begins either when none of the steam from the boiler is 

used to generate electricity for sale over the grid or for any other purpose (including on-site 

use) or at the point of no fuel being fired in the boiler. Shutdown ends when there is both no 

electricity being generated and no fuel being fired in the boiler. During shutdown, you must 

operate all applicable control technologies while firing coal, residual oil, or solid oil-derived 

fuel. You must comply with all applicable emissions limits at all times except for periods that 

meet the definitions of startup and shutdown in this subpart. You must keep records during 

periods of startup. You must provide reports concerning activities and periods of startup, as 

specified in § 63.10011(g) and § 63.10021(h) and (i). 

TABLE 4 TO SUBPART UUUUU OF PART 63—OPERATING LIMITS FOR EGUS

[As stated in § 63.9991, you must comply with the applicable operating limits] 

If you demonstrate compliance using . . . You must meet these operating limits . . . 

1. PM CPMS ....................................................... Maintain the 30-boiler operating day rolling average PM CPMS output at or below the highest 

1-hour average measured during the most recent performance test demonstrating compliance with the filterable PM, total non-mercury HAP metals (total HAP metals, for liquid oilfired units), or individual non-mercury HAP metals (individual HAP metals including Hg, for 

liquid oil-fired units) emissions limitation(s). 

TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS

[As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected 

sources 1] 

To conduct a performance test for the following pollutant . . . 

Using . . . 

You must perform the following activities, as 

applicable to your input- or output-based 

emission limit . . . 

Using 2 . . . 

1. Filterable Particulate 

matter (PM).

Emissions Testing ...... a. Select sampling ports location and the 

number of traverse points.

Method 1 at Appendix A–1 to part 60 of this 

chapter. 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2A, 2C, 2F, 2G or 2H at Appendix 

A–1 or A–2 to part 60 of this chapter. 

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B at Appendix A–2 to part 60 

of this chapter, or ANSI/ASME PTC 19.10– 

1981.3

d. Measure the moisture content of the stack 

gas.

Method 4 at Appendix A–3 to part 60 of this 

chapter. 

e. Measure the filterable PM concentration .... Method 5 at Appendix A–3 to part 60 of this 

chapter. 

For positive pressure fabric filters, Method 5D 

at Appendix A–3 to part 60 of this chapter 

for filterable PM emissions. 

Note that the Method 5 front half temperature 

shall be 160 ° ± 14 °C (320 ° ± 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)). 

OR OR 

PM CEMS a. Install, certify, operate, and maintain the 

PM CEMS.

Performance Specification 11 at Appendix B 

to part 60 of this chapter and Procedure 2 

at Appendix F to Part 60 of this chapter. 

b. Install, certify, operate, and maintain the 

diluent gas, flow rate, and/or moisture monitoring systems.

Part 75 of this chapter and §§ 63.10010(a), 

(b), (c), and (d). 

c. Convert hourly emissions concentrations to 

30 boiler operating day rolling average lb/ 

MMBtu or lb/MWh emissions rates.

Method 19 F-factor methodology at Appendix 

A–7 to part 60 of this chapter, or calculate 

using mass emissions rate and electrical 

output data (see § 63.10007(e)). 

2. Total or individual 

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 A–2 to part 60 of this chapter. 


srobinson on DSK4SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9495 

TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued 

[As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected 

sources 1] 

To conduct a performance test for the following pollutant . . . 

Using . . . 

You must perform the following activities, as 

applicable to your input- or output-based 

emission limit . . . 

Using 2 . . . 

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B at Appendix A–2 to part 60 

of this chapter, or ANSI/ASME PTC 19.10– 

1981.3

d. Measure the moisture content of the stack 

gas.

Method 4 at Appendix A–3 to part 60 of this 

chapter. 

e. Measure the HAP metals emissions concentrations and determine each individual 

HAP metals emissions concentration, as 

well as the total filterable HAP metals 

emissions concentration and total HAP 

metals emissions concentration.

Method 29 at Appendix A–8 to part 60 of this 

chapter. For liquid oil-fired units, Hg is included in HAP metals and you may use 

Method 29, Method 30B at Appendix A–8 

to part 60 of this chapter; for Method 29, 

you must report the front half and back half 

results separately. 

f. Convert emissions concentrations (individual HAP metals, total filterable HAP 

metals, and total HAP metals) to lb/MMBtu 

or lb/MWh emissions rates.

Method 19 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 A–2 to part 60 of this chapter. 

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B at Appendix A–2 to part 60 

of this chapter, or ANSI/ASME PTC 19.10– 

1981.3

d. Measure the moisture content of the stack 

gas.

Method 4 at Appendix A–3 to part 60 of this 

chapter. 

e. Measure the HCl and HF emissions concentrations.Method 26 or Method 26A at Appendix A–8 

to part 60 of this chapter or Method 320 at 

Appendix A to part 63 of this chapter or 

ASTM 6348–03 3 with (1) additional quality 

assurance measures in footnote 4 and (2) 

spiking levels nominally no greater than 

two times the level corresponding to the 

applicable emission limit. Method 26A must 

be used if there are entrained water droplets in the exhaust stream. 

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)). 

OR OR 

HCl and/or HF CEMS a. Install, certify, operate, and maintain the 

HCl or HF CEMS.

Appendix B of this subpart. 

b. Install, certify, operate, and maintain the 

diluent gas, flow rate, and/or moisture monitoring systems.

Part 75 of this chapter and §§ 63.10010(a), 

(b), (c), and (d). 

c. Convert hourly emissions concentrations to 

30 boiler operating day rolling average lb/ 

MMBtu or lb/MWh emissions rates.

Method 19 F-factor methodology at Appendix 

A–7 to part 60 of this chapter, or calculate 

using mass emissions rate and electrical 

output data (see § 63.10007(e)). 

4. Mercury (Hg) ........... Emissions Testing ...... a. Select sampling ports location and the 

number of traverse points.

Method 1 at Appendix A–1 to part 60 of this 

chapter or Method 30B at Appendix A–8 

for Method 30B 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 A–2 to part 60 of this chapter. 

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B at Appendix A–1 to part 60 

of this chapter, or ANSI/ASME PTC 19.10– 

1981.3

d. Measure the moisture content of the stack 

gas.

Method 4 at Appendix A–3 to part 60 of this 

chapter. 

e. Measure the Hg emission concentration .... Method 30B at Appendix A–8 to part 60 of 

this chapter, ASTM D6784 3, 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. 


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TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued 

[As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected 

sources 1] 

To conduct a performance test for the following pollutant . . . 

Using . . . 

You must perform the following activities, as 

applicable to your input- or output-based 

emission limit . . . 

Using 2 . . . 

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)). 

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 A– 

8 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 A–2 to part 60 of this chapter or 

flow monitoring system certified per Appendix A of this subpart. 

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B at Appendix A–1 to part 60 

of this chapter, or ANSI/ASME PTC 19.10– 

1981,3 or diluent gas monitoring systems 

certified according to Part 75 of this chapter. 

d. Measure the 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)). 

g. Convert average lb/TBtu or lb/GWh Hg 

emission rate to lb/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)). 

1 Regarding emissions data collected during periods of startup or shutdown, see §§ 63.10020(b) and (c) and § 63.10021(h). 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9497 

2See Tables 1 and 2 to this subpart for required sample volumes and/or sampling run times. 

3 Incorporated by reference, see § 63.14. 

4When using ASTM D6348–03, the following conditions must be met: (1) The test plan preparation and implementation in the Annexes to 

ASTM D6348–03, Sections A1 through A8 are mandatory; (2) For ASTM D6348–03 Annex A5 (Analyte Spiking Technique), the percent (%) R 

must be determined for each target analyte (see Equation A5.5); (3) For the ASTM D6348–03 test data to be acceptable for a target analyte, %R 

must be 70% ≥ R ≤ 130%; and (4) The %R value for each compound must be reported in the test report and all field measurements corrected 

with the calculated %R value for that compound using the following equation: 

TABLE 6 TO SUBPART UUUUU OF PART 63—ESTABLISHING PM CPMS OPERATING LIMITS

[As stated in § 63.10007, you must comply with the following requirements for establishing operating limits] 

If you have an applicable 

emission limit for . . . 

And you choose to establish 

PM CPMS operating limits, 

you must . . . 

And . . . Using . . . According to the following 

procedures . . . 

Particulate matter (PM), 

total non-mercury HAP 

metals, individual nonmercury HAP metals, 

total HAP metals, individual HAP metals.

Install, certify, maintain, and 

operate a PM CPMS for 

monitoring emissions discharged to the atmosphere 

according to 

§ 63.10010(g)(1).

Establish a site-specific 

operating limit in units 

of PM CPMS output 

signal (e.g., milliamps, 

mg/acm, or other raw 

signal).

Data from the PM CPMS 

and the PM or HAP 

metals performance 

tests.

1. Collect PM CPMS output data during the entire period of the performance tests. 

2. Record the average 

hourly PM CPMS output for each test run in 

the three run performance test. 

3. Determine the highest 

1-hour average PM 

CPMS measured during the performance 

test demonstrating 

compliance with the filterable PM or HAP 

metals emissions limitations. 

TABLE 7 TO SUBPART UUUUU OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE

[As stated in § 63.10021, you must show continuous compliance with the emission limitations for affected sources according to the following] 

If you use one of the following to meet applicable emissions limits, operating limits, or work practice standards . . . You demonstrate continuous compliance by . . . 

1. CEMS to measure filterable PM, SO2, HCl, HF, or Hg emissions, or 

using a sorbent trap monitoring system to measure Hg.

Calculating the 30-boiler operating day rolling arithmetic average emissions rate in units of the applicable emissions standard basis at the 

end of each boiler operating day using all of the quality assured 

hourly average CEMS or sorbent trap data for the previous 30 boiler 

operating days, excluding data recorded during periods of startup or 

shutdown. 

2. PM CPMS to measure compliance with a parametric operating limit Calculating the arithmetic 30-boiler operating day rolling average of all 

of the quality assured hourly average PM CPMS output data (e.g., 

milliamps, PM concentration, raw data signal) collected for all operating hours for the previous 30 boiler operating days, excluding data 

recorded during periods of startup or shutdown. 

3. Site-specific monitoring for liquid oil-fired units for HCl and HF emission limit monitoring.If applicable, by conducting the monitoring in accordance with an approved site-specific monitoring plan. 

4. Quarterly performance testing for coal-fired, solid oil derived fired, or 

liquid oil-fired units to measure compliance with one or more applicable emissions limit in Table 1 or 2.

Calculating the results of the testing in units of the applicable emissions standard. 

5. Conducting periodic performance tune-ups of your EGU(s) ................ Conducting periodic performance tune-ups of your EGU(s), as specified in § 63.10021(e). 

6. Work practice standards for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs during startup.Operating in accordance with Table 3. 

7. Work practice standards for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs during shutdown.Operating in accordance with Table 3. 


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TABLE 8 TO SUBPART UUUUU OF PART 63—REPORTING REQUIREMENTS

[As stated in § 63.10031, you must comply with the following requirements for reports] 

You must submit a . . . The report must contain . . . You must submit the report . . . 

1. Compliance report .......... a. Information required in § 63.10031(c)(1) through (4); and 

b. If there are no deviations from any emission limitation (emission limit and operating limit) that applies to you and there are no deviations from the requirements for work practice standards in Table 3 to this subpart that apply to you, 

a statement that there were no deviations from the emission limitations and 

work practice standards during the reporting period. If there were no periods 

during which the CMSs, including continuous emissions monitoring system, 

and operating parameter monitoring systems, were out-of-control as specified 

in § 63.8(c)(7), a statement that there were no periods during which the CMSs 

were out-of-control during the reporting period; and 

Semiannually according to the 

requirements in 

§ 63.10031(b). 

c. If you have a deviation from any emission limitation (emission limit and operating limit) or work practice standard during the reporting period, the report 

must contain the information in § 63.10031(d). If there were periods during 

which the CMSs, including continuous emissions monitoring systems and 

continuous parameter monitoring systems, were out-of-control, as specified in 

§ 63.8(c)(7), the report must contain the information in § 63.10031(e).

TABLE 9 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU 

[As stated in § 63.10040, you must comply with the applicable General Provisions according to the following] 

Citation Subject Applies to subpart UUUUU 

§ 63.1 ................................................................. Applicability ....................................................... Yes. 

§ 63.2 ................................................................. Definitions ......................................................... Yes. Additional terms defined in § 63.10042. 

§ 63.3 ................................................................. Units and Abbreviations ................................... Yes. 

§ 63.4 ................................................................. Prohibited Activities and Circumvention ........... Yes. 

§ 63.5 ................................................................. Preconstruction Review and Notification Requirements.Yes. 

§ 63.6(a), (b)(1)–(b)(5), (b)(7), (c), (f)(2)–(3), 

(g), (h)(2)–(h)(9), (i), (j).

Compliance with Standards and Maintenance 

Requirements.

Yes. 

§ 63.6(e)(1)(i) ..................................................... General Duty to minimize emissions ............... No. See § 63.10000(b) for general duty requirement. 

§ 63.6(e)(1)(ii) ..................................................... Requirement to correct malfunctions ASAP .... No. 

§ 63.6(e)(3) ......................................................... SSM Plan requirements ................................... No.

§ 63.6(f)(1) .......................................................... SSM exemption ................................................ No. 

§ 63.6(h)(1) ......................................................... SSM exemption ................................................ No. 

§ 63.7(a), (b), (c), (d), (e)(2)–(e)(9), (f), (g), and 

(h).

Performance Testing Requirements ................ Yes. 

§ 63.7(e)(1) ......................................................... Performance testing ......................................... No. See § 63.10007. 

§ 63.8 ................................................................. Monitoring Requirements ................................. Yes. 

63.8(c)(1)(i) ........................................................ General duty to minimize emissions and CMS 

operation.

No. See § 63.10000(b) for general duty requirement. 

§ 63.8(c)(1)(iii) .................................................... Requirement to develop SSM Plan for CMS ... No. 

§ 63.8(d)(3) ......................................................... Written procedures for CMS ............................ Yes, except for last sentence, which refers to 

an SSM plan. SSM plans are not required. 

§ 63.9 ................................................................. Notification Requirements ................................ Yes. 

§ 63.10(a), (b)(1), (c), (d)(1)–(2), (e), and (f) ..... Recordkeeping and Reporting Requirements .. Yes, except for the requirements to submit 

written reports under § 63.10(e)(3)(v). 

§ 63.10(b)(2)(i) ................................................... Recordkeeping of occurrence and duration of 

startups and shutdowns.

No. 

§ 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. 


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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations 9499 

TABLE 9 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU—Continued 

[As stated in § 63.10040, you must comply with the applicable General Provisions according to the following] 

Citation Subject Applies to subpart UUUUU 

§ 63.10(c)(11) ..................................................... Recording corrective actions ............................ No. See 63.10032(g) and (h) for malfunctions 

recordkeeping requirements. 

§ 63.10(c)(15) ..................................................... Use of SSM Plan .............................................. No. 

§ 63.10(d)(5) ....................................................... SSM reports ..................................................... No. See 63.10021(h) and (i) for malfunction 

reporting requirements. 

§ 63.11 ............................................................... Control Device Requirements .......................... No. 

§ 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. 

Appendix A to Subpart UUUUU—Hg 

Monitoring Provisions 

1. General Provisions 

1.1 Applicability. These monitoring 

provisions apply to the measurement of total 

vapor phase mercury (Hg) in emissions from 

electric utility steam generating units, using 

either a mercury continuous emission 

monitoring system (Hg CEMS) or a sorbent 

trap monitoring system. The Hg CEMS or 

sorbent trap monitoring system must be 

capable of measuring the total vapor phase 

mercury in units of the applicable emissions 

standard (e.g., lb/TBtu or lb/GWh), regardless 

of speciation. 

1.2 Initial Certification and 

Recertification Procedures. The owner or 

operator of an affected unit that uses a Hg 

CEMS or a sorbent trap monitoring system 

together with other necessary monitoring 

components to account for Hg emissions in 

units of the applicable emissions standard 

shall comply with the initial certification and 

recertification procedures in section 4 of this 

appendix. 

1.3 Quality Assurance and Quality 

Control Requirements. The owner or operator 

of an affected unit that uses a Hg CEMS or 

a sorbent trap monitoring system together 

with other necessary monitoring components 

to account for Hg emissions in units of the 

applicable emissions standard shall meet the 

applicable quality assurance requirements in 

section 5 of this appendix. 

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 qualityassured Hg concentration data are not 

obtained is counted as an hour of monitoring 

system downtime. 

2. Monitoring of Hg Emissions 

2.1 Monitoring System Installation 

Requirements. Flue gases from the affected 

units under this subpart vent to the 

atmosphere through a variety of exhaust 

configurations including single stacks, 

common stack configurations, and multiple 

stack configurations. For each of these 

configurations, § 63.10010(a) specifies the 

appropriate location(s) at which to install 

continuous monitoring systems (CMS). These 

CMS installation provisions apply to the Hg 

CEMS, sorbent trap monitoring systems, and 

other continuous monitoring systems that 

provide data for the Hg emissions 

calculations in section 6.2 of this appendix. 

2.2 Primary and Backup Monitoring 

Systems. In the electronic monitoring plan 

described in section 7.1.1.2.1 of this 

appendix, you must designate a primary Hg 

CEMS or sorbent trap monitoring system. The 

primary system must be used to report hourly 

Hg concentration values when the system is 

able to provide quality-assured data, i.e., 

when the system is ‘‘in control’’. However, to 

increase data availability in the event of a 

primary monitoring system outage, you may 

install, operate, maintain, and calibrate 

backup monitoring systems, as follows: 

2.2.1 Redundant Backup Systems. A 

redundant backup monitoring system may be 

either a separate Hg CEMS with its own 

probe, sample interface, and analyzer, or a 

separate sorbent trap monitoring system. A 

redundant backup system is one that is 

permanently installed at the unit or stack 

location, and is kept on ‘‘hot standby’’ in case 

the primary monitoring system is unable to 

provide quality-assured data. A redundant 

backup system must be represented as a 

unique monitoring system in the electronic 

monitoring plan. Each redundant backup 

monitoring system must be certified 

according to the applicable provisions in 

section 4 of this appendix and must meet the 

applicable on-going QA requirements in 

section 5 of this appendix. 

2.2.2 Non-redundant Backup Monitoring 

Systems. A non-redundant backup 

monitoring system is a separate Hg CEMS or 

sorbent trap system that has been certified at 

a particular unit or stack location, but is not 

permanently installed at that location. 

Rather, the system is kept on ‘‘cold standby’’ 

and may be reinstalled in the event of a 

primary monitoring system outage. A nonredundant 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 nonredundant backup monitoring system may 

only be used for 720 hours per year at a 

particular unit or stack location. 

2.2.3 Temporary Like-kind Replacement 

Analyzers. When a primary Hg analyzer 

needs repair or maintenance, you may 

temporarily install a like-kind replacement 

analyzer, to minimize data loss. Except as 

otherwise provided in section 2.2.4.5 of this 

appendix, a temporary like-kind replacement 

analyzer may only be used for 720 hours per 

year at a particular unit or stack location. The 

analyzer must be represented as a component 

of the primary Hg CEMS, and must be 

assigned a 3-character component ID number, 

beginning with the prefix ‘‘LK’’. 

2.2.4 Quality Assurance Requirements for 

Non-redundant Backup Monitoring Systems 

and Temporary Like-kind Replacement 

Analyzers. To quality-assure the data from 

non-redundant backup Hg monitoring 

systems and temporary like-kind replacement 

Hg analyzers, the following provisions apply: 

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 qualityassurance of a non-redundant backup Hg 

monitoring system, a relative accuracy test 

audit (RATA) must be performed and passed 

at least once every 8 calendar quarters at the 


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unit or stack location(s) where the system 

will be used. 

2.2.4.5 To use a non-redundant backup 

Hg monitoring system or a temporary likekind 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 vaporphase 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 timeintegrated, batch sampling systems that 

sample the gas on an intermittent basis and 

concentrate on a collection medium 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 (mg/dscm), based on the 

sample volume measured by the gas flow 

meter and the mass of Hg collected in the 

sorbent traps. 

3.1.3 NIST means the National Institute 

of Standards and Technology, located in 

Gaithersburg, Maryland. 

3.1.4 NIST–Traceable Elemental Hg 

Standards means either: compressed gas 

cylinders having known concentrations of 

elemental Hg, which have been prepared 

according to the ‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards’’; or calibration gases 

having known concentrations of elemental 

Hg, produced by a generator that meets the 

performance requirements of the ‘‘EPA 

Traceability 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 NISTtraceable gas standard containing a known 

concentration of elemental or oxidized Hg 

that is produced and certified in accordance 

with an EPA traceability protocol. 

3.1.7 Span Value means a conservatively 

high estimate of the Hg concentrations to be 

measured by a CEMS. The span value of a Hg 

CEMS should be set to approximately twice 

the concentration corresponding to the 

emission standard, rounded off as 

appropriate (see section 3.2.1.4.2 of this 

appendix). 

3.1.8 Zero-Level Gas means calibration 

gas containing a Hg concentration that is 

below the level detectable by the Hg gas 

analyzer in use. 

3.1.9 Low-Level Gas means calibration gas 

with a concentration that is 20 to 30 percent 

of the span value. 

3.1.10 Mid-Level Gas means calibration 

gas with a concentration 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 highlevel gas may be used, and the gas may either 

be an elemental or oxidized Hg standard. 

3.1.13 Linearity Check means a test 

designed to determine whether the response 

of a Hg analyzer is linear across its 

measurement range. Three elemental Hg 

calibration gas standards (i.e., low, mid, and 

high-level gases) are required for this test. 

3.1.14 System Integrity Check means a 

test designed to assess the transport and 

measurement of oxidized Hg by a Hg CEMS. 

Oxidized Hg standards are used for this test. 

For a three-level system integrity check, low, 

mid, and high-level calibration gases are 

required. For a single-level check, either a 

mid-level gas or a high-level gas may be used. 

3.1.15 Cycle Time Test means a test 

designed to measure the amount of time it 

takes for a Hg CEMS, while operating 

normally, to respond to a known step change 

in gas concentration. For this test, a zero gas 

and a high-level gas are required. The highlevel gas may be either an elemental or an 

oxidized Hg standard. 

3.1.16 Relative Accuracy Test Audit or 

RATA means a series of nine or more test 

runs, directly comparing readings from a Hg 

CEMS or sorbent trap monitoring system to 

measurements made with a reference stack 

test method. The relative accuracy (RA) of 

the monitoring system is expressed as the 

absolute mean difference between the 

monitoring system and reference method 

measurements plus the absolute value of the 

2.5 percent error confidence coefficient, 

divided by the mean value of the reference 

method measurements. 

3.1.17 Unit Operating Hour means a 

clock hour in which a unit combusts any 

fuel, either for part of the hour or for the 

entire hour. 

3.1.18 Stack Operating Hour means a 

clock hour in which gases flow through a 

particular monitored stack or duct (either for 

part of the hour or for the entire hour), while 

the associated unit(s) are combusting fuel. 

3.1.19 Operating Day means a calendar 

day in which a source combusts any fuel. 

3.1.20 Quality Assurance (QA) Operating 

Quarter means a calendar quarter in which 

there are at least 168 unit or stack operating 

hours (as defined in this section). 

3.1.21 Grace Period means a specified 

number of unit or stack operating hours after 

the deadline for a required quality-assurance 

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. 


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3.2.1.1 Equipment Specifications. 

3.2.1.1.1 Materials of Construction. All 

wetted sampling system components, 

including probe components prior to the 

point at which the calibration gas is 

introduced, must be chemically inert to all 

Hg species. Materials such as perfluoroalkoxy 

(PFA) TeflonTM, quartz, and treated stainless 

steel (SS) are examples of such materials. 

3.2.1.1.2 Temperature Considerations. 

All system components prior to the Hg∂2 to 

Hg0 converter must be maintained at a 

sample temperature above the acid gas dew 

point. 

3.2.1.1.3 Measurement System 

Components. 

3.2.1.1.3.1 Sample Probe. The probe must 

be made of the appropriate materials as noted 

in paragraph 3.2.1.1.1 of this section, heated 

when necessary, as described in paragraph 

3.2.1.1.3.4 of this section, and configured 

with ports for introduction of calibration 

gases. 

3.2.1.1.3.2 Filter or Other Particulate 

Removal Device. The filter or other 

particulate removal device is part of the 

measurement system, must be made of 

appropriate materials, as noted in paragraph 

3.2.1.1.1 of this section, and must be 

included in all system tests. 

3.2.1.1.3.3 Sample Line. The sample line 

that connects the probe to the converter, 

conditioning system, and analyzer must be 

made of appropriate materials, as noted in 

paragraph 3.2.1.1.1 of this section. 

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 

through a critical orifice at a constant rate. 

The ejector pump must be constructed of any 

material that is non-reactive to the gas being 

sampled. 

3.2.1.1.3.6 Calibration Gas System(s). 

Design and equip each Hg CEMS to permit 

the introduction of known concentrations of 

elemental Hg and HgCl2 separately, at a point 

preceding the sample extraction filtration 

system, such that the entire measurement 

system can be checked. The calibration gas 

system(s) must be designed so that the flow 

rate exceeds the sampling system flow 

requirements and that the gas is delivered to 

the CEMS at atmospheric pressure. 

3.2.1.1.3.7 Sample Gas Delivery. The 

sample line may feed directly to either a 

converter, a by-pass valve (for Hg speciating 

systems), or a sample manifold. All valve 

and/or manifold components must be made 

of material that is non-reactive 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, or 

data logger, is required for recording 

measurement data. 

3.2.1.2 Reagents and Standards. 

3.2.1.2.1 NIST Traceability. Only NISTcertified or NIST-traceable 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 concentration of 50 


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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 

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 mg/scm for all coal ranks 

(including coal refuse) except for lignite; for 

lignite, use 16 mg/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 sitespecific Hg emission testing. This option may 

be used only if the unit does not have addon 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 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 mg/scm, use the result as the span value. 

Otherwise, round off the result to either: the 

next highest integer; the next highest 

multiple of 5 mg/scm; or the next highest 

multiple of 10 mg/scm. 

3.2.1.4.3 Analyzer Range. The Hg 

analyzer must be capable of reading Hg 

concentration as high as the MPC. 

3.2.2 Sorbent Trap Monitoring System. A 

sorbent trap monitoring system (as defined in 

paragraph 3.1.2 of this section) may be used 

as an alternative to a Hg CEMS. If this option 

is selected, the monitoring system shall be 

installed, maintained, and operated in 

accordance with Performance Specification 

(PS) 12B in Appendix B to part 60 of this 

chapter. The system shall be certified in 

accordance with the provisions of section 

4.1.2 of this appendix. 

3.2.3 Other Necessary Data Collection. To 

convert measured hourly Hg concentrations 

to the units of the applicable emissions 

standard (i.e., lb/TBtu or lb/GWh), additional 

data 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 fuelspecific 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 established ratio of stack gas 

flow rate to sample flow rate. 

4. Certification and Recertification 

Requirements 

4.1 Certification Requirements. All Hg 

CEMS and sorbent trap monitoring systems 

and the additional monitoring systems used 

to continuously measure Hg emissions in 

units of the applicable emissions standard in 

accordance with this appendix must be 

certified in a timely manner, such that the 

initial compliance demonstration is 

completed no later than the applicable date 

in § 63.10005(g). 

4.1.1 Hg CEMS. Table A–1, below, 

summarizes the certification test 

requirements and performance specifications 

for a Hg CEMS. The CEMS may not be used 

to report quality-assured data until these 

performance criteria are met. Paragraphs 

4.1.1.1 through 4.1.1.5 of this section provide 

specific instructions for the required tests. 

All tests must be performed with the affected 

unit(s) operating (i.e., combusting fuel). 

Except for the RATA, which must be 

performed at normal load, no particular load 

level is required for the certification tests. 

4.1.1.1 7-Day Calibration Error Test. 

Perform the 7-day calibration error test on 7 

consecutive source operating days, using a 

zero-level gas and either a high-level or a 

mid-level calibration gas standard (as defined 

in sections 3.1.8, 3.1.10, and 3.1.11 of this 

appendix). Either elemental or oxidized 

NIST-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 zerolevel 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. 

4.1.1.2 Linearity Check. Perform the 

linearity check using low, mid, and highlevel 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 


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check using low, mid, and high-level 

calibration gas concentrations generated by a 

NIST-traceable 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 specification 1 is . . . The alternate performance specification 1 is . . . 

And the conditions of the alternate specification are . . . 

7-day calibration error test 2 ........... ⎢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 check 3 ............................. ⎢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 check 4 ..... ⎢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 test 2 ............................. 15 minutes.5

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. 

5Stability criteria—Readings change by <2.0% of span or by ≤0.5 μg/scm, for 2 minutes. 

** Note that ⎢RMavg¥Cavg ⎢ is the absolute difference between the mean reference method value and the mean CEMS value from the RATA. 

The arithmetic difference between RMavg and Cavg can be either + or ¥. 

4.1.1.4 Cycle Time Test. Perform the 

cycle time test, using a zero-level gas and a 

high-level calibration gas. 

Either an elemental or oxidized NISTtraceable 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 mg/scm (whichever is less restrictive) 

for two minutes, or a reading with a change 

of less than 6.0 percent from the measured 

average concentration over 6 minutes. 

Integrated batch sampling type Hg CEMS are 

exempted from this test; however, these 

systems must be capable of delivering a 

measured Hg concentration reading at least 

once every 15 minutes. If necessary to 

increase measurement sensitivity of a batch 

sampling type Hg CEMS for a specific 

application, you may petition the 

Administrator for approval of a time longer 

than 15 minutes between readings. 

4.1.1.5 Relative Accuracy Test Audit 

(RATA). Perform the RATA of the Hg CEMS 

at normal load. Acceptable Hg reference 

methods for the RATA include ASTM 

D6784–02 (Reapproved 2008), ‘‘Standard 

Test Method for Elemental, Oxidized, 

Particle-Bound and Total Mercury in Flue 

Gas Generated from Coal-Fired Stationary 

Sources (Ontario Hydro Method)’’ 

(incorporated by reference, see § 63.14) 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 mg/dscm. If the average 

concentration is ≤ 1.0 mg/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 mg/dscm. If the RD specification 

is met, the results of the two samples shall 

be averaged arithmetically. 

Where: 

RD = Relative deviation between the Hg 

concentrations of samples ‘‘a’’ and ‘‘b’’ 

(percent) 

Ca = Hg concentration of Hg sample ‘‘a’’ (mg/ 

dscm) 

Cb = Hg concentration of Hg sample ‘‘b’’ (mg/ 

dscm) 

4.1.1.5.1 Special Considerations. A 

minimum of nine valid test runs must be 

performed, directly comparing the CEMS 

measurements to the reference method. More 

than nine test runs may be performed. If this 

option is chosen, the results from a 

maximum of three test runs may be rejected 

so long as the total number of test results 

used to determine the relative accuracy is 

greater than or equal to nine; however, all 

data must be reported including the rejected 

data. The minimum time per run is 21 

minutes if Method 30A is used. If Method 29, 

Method 30B, or ASTM D6784–02 

(Reapproved 2008), ‘‘Standard Test Method 

for Elemental, Oxidized, Particle-Bound and 

Total Mercury in Flue Gas Generated from 

Coal-Fired Stationary Sources (Ontario Hydro 

Method)’’ (incorporated by reference, see 

§ 63.14) is used, the time per run must be 

long enough to collect a sufficient mass of Hg 

to analyze. Complete the RATA within 168 

unit operating hours, except when Method 29 

or ASTM D6784–02 is used, in which case 

up to 336 operating hours may be taken to 

finish the test. 

4.1.1.5.2 Calculation of RATA Results. 

Calculate the relative accuracy (RA) of the 

monitoring system, on a mg/scm basis, as 

described in section 12 of Performance 

Specification (PS) 2 in Appendix B to part 60 

of this chapter (see Equations 2–3 through 2– 

6 of PS2). For purposes of calculating the 

relative accuracy, ensure that the reference 

method and monitoring system data are on a 

consistent moisture basis, either wet or dry. 

The CEMS must either meet the main 

performance specification or the alternative 

specification in Table A–1. 

4.1.1.5.3 Bias Adjustment. Measurement 

or adjustment of Hg CEMS data for bias is not 

required. 

4.1.2 Sorbent Trap Monitoring Systems. 

For the initial 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 ‘‘The special considerations 

specified in paragraph 4.1.1.5.1 of this 

section apply to the RATA of a sorbent trap 


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monitoring system. During the RATA, the 

monitoring system must be operated and 

quality-assured in accordance with 

Performance Specification (PS) 12B in 

Appendix B to part 60 of this chapter with 

the following exceptions for sorbent trap 

section 2 breakthrough: 

4.1.2.2.1 For stack Hg concentrations >1 

mg/dscm, ≤10% of section 1 Hg mass; 

4.1.2.2.2 For stack Hg concentrations ≤1 

mg/dscm and >0.5 mg/dscm, ≤ 20% of section 

1 Hg mass; 

4.1.2.2.3 For stack Hg concentrations ≤0.5 

mg/dscm and >0.1 mg/dscm, ≤ 50% of section 

1 Hg mass; and 

4.1.2.2.4 For stack Hg concentrations 

≤0.1mg/dscm, no breakthrough criterion 

assuming all other QA/QC specifications are 

met. 

4.1.2.3 The type of sorbent material used 

by the traps during the RATA must be the 

same as for daily operation of the monitoring 

system; however, the size of the traps used 

for the RATA may be smaller than the traps 

used for daily operation of the system. 

4.1.2.4 Calculation of RATA Results. 

Calculate the relative accuracy (RA) of the 

sorbent trap monitoring system, on a mg/scm 

basis, as described in section 12 of 

Performance Specification (PS) 2 in appendix 

B to part 60 of this chapter (see Equations 2– 

3 through 2–6 of PS2). For purposes of 

calculating the relative accuracy, ensure that 

the reference method and monitoring system 

data are on a consistent moisture basis, either 

wet or dry.The main and alternative RATA 

performance specifications in Table A–1 for 

Hg CEMS also apply to the sorbent trap 

monitoring system. 

4.1.2.5 Bias Adjustment. Measurement or 

adjustment of sorbent trap monitoring system 

data for bias is not required. 

4.1.3 Diluent Gas, Flow Rate, and/or 

Moisture Monitoring Systems. Monitoring 

systems that are used to measure stack gas 

volumetric flow rate, diluent gas 

concentration, or stack gas moisture content, 

either for routine operation of a sorbent trap 

monitoring system or to convert Hg 

concentration data to units of the applicable 

emission limit, must be certified in 

accordance with the applicable provisions of 

part 75 of this chapter. 

4.2 Recertification. Whenever the owner 

or operator makes a replacement, 

modification, or change to a certified CEMS 

or sorbent trap monitoring system that may 

significantly affect the ability of the system 

to accurately measure or record pollutant or 

diluent gas concentrations, stack gas flow 

rates, or stack gas moisture content, the 

owner or operator shall recertify the 

monitoring system. Furthermore, whenever 

the owner or operator makes a replacement, 

modification, or change to the flue gas 

handling system or the unit operation that 

may significantly change the concentration or 

flow profile, the owner or operator shall 

recertify the monitoring system. The same 

tests performed for the initial certification of 

the monitoring system shall be repeated for 

recertification, unless otherwise specified by 

the Administrator. Examples of changes that 

require recertification include: replacement 

of a gas analyzer; complete monitoring 

system replacement, and changing the 

location or orientation of the sampling probe. 

5. Ongoing Quality Assurance (QA) and Data 

Validation 

5.1 Hg CEMS. 

5.1.1 Required QA Tests. Periodic QA 

testing of each Hg CEMS is required 

following initial certification. The required 

QA tests, the test frequencies, and the 

performance specifications that must be met 

are summarized in Table A–2, below. All 

tests must be performed with the affected 

unit(s) operating (i.e., combusting fuel). 

Except for the RATA, which must be 

performed at normal load, no particular load 

level is required for the tests. For each test, 

follow the same basic procedures in section 

4.1.1 of this appendix that were used for 

initial certification. 

5.1.2 Test Frequency. The frequency for 

the required QA tests of the Hg CEMS shall 

be as follows: 

5.1.2.1 Calibration error tests of the Hg 

CEMS are required daily, except during unit 

outages. Use either NIST-traceable elemental 

Hg standards or NIST-traceable oxidized Hg 

standards for these calibrations. Both a zerolevel gas and either a mid-level 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. 

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 non-QA 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 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-of-control, and data 

from the CEMS may not be reported as 

quality-assured, 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-ofcontrol 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) of this chapter. Required 

system integrity checks must be completed 

within 168 unit or stack operating hours after 

the probationary calibration error test. 

TABLE A–2—ON-GOING QA TEST REQUIREMENTS FOR Hg CEMS 

Perform this type of QA test . . . At this frequency . . . With these qualifications and exceptions . . . Acceptance criteria . . . 

Calibration error test ...................... Daily .............................................. • Use either a mid- or high-level 

gas.

⎢R¥A⎢ ≤ 5.0% of span value. 

or 

⎢R¥A⎢ ≤ 1.0 μg/scm. 

• Use either elemental or 

oxidized Hg.


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TABLE A–2—ON-GOING QA TEST REQUIREMENTS FOR Hg CEMS—Continued 

Perform this type of QA test . . . At this frequency . . . With these qualifications and exceptions . . . Acceptance criteria . . . 

• Calibrations are not required 

when the unit is not in operation.

Single-level system integrity check Weekly 1 ........................................ • Required only for systems with 

converters.

⎢R¥Aavg ⎢ ≤ 10.0% of the reference gas value. 

or 

⎢R¥Aavg ⎢ ≤ 0.8 μg/scm. 

• Use oxidized Hg—either mid- or 

high-level.

• Not required if daily calibrations 

are done with a NIST-traceable 

source of oxidized Hg.

Linearity check 

or 

3-level system integrity check 

Quarterly 3 ..................................... • Required in each ‘‘QA operating 

quarter’’ 2—and no less than 

once every 4 calendar quarters.

⎢R¥Aavg ⎢ ≤ 10.0% of the reference gas value, at each calibration gas level. 

or 

⎢R¥Aavg ⎢ ≤ 0.8 μg/scm. 

• 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.

RATA ............................................. Annual 4 ........................................ • Test deadline may be extended 

for ‘‘non-QA operating quarters’’, up to a maximum of 8 

quarters from the quarter of the 

previous test.

20.0% RA. 

or 

⎢RMavg¥Cavg ⎢ ≤ 1.0 μg/scm, 

if 

RMavg < 5.0 μg/scm. 

• 720 operating hour grace period available.

1 ‘‘Weekly’’ means once every 7 operating days. 

2A ‘‘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. 

5.1.6 Adjustment of Span. If you discover 

that a span adjustment is needed (e.g., if the 

Hg concentration readings exceed the span 

value for a significant percentage of the unit 

operating hours in a calendar quarter), you 

must implement the span adjustment within 

90 days after the end of the calendar quarter 

in which you identify the need for the 

adjustment. A diagnostic linearity check is 

required within 168 unit or stack operating 

hours after changing the span value. 

5.2 Sorbent Trap Monitoring Systems. 

5.2.1 Each sorbent trap monitoring 

system shall be continuously operated and 

maintained in accordance with Performance 

Specification (PS) 12B in appendix B to part 

60 of this chapter. The QA/QC criteria for 

routine operation of the system are 

summarized in Table 12B–1 of PS 12B. Each 

pair of sorbent traps may be used to sample 

the stack gas for up to 14 operating days. 

5.2.2 For ongoing QA, periodic RATAs of 

the system are required. 

5.2.2.1 The RATA frequency shall be 

annual, i.e., once every four QA operating 

quarters. The provisions in section 5.1.2.4 of 

this appendix pertaining to RATA deadline 

extensions also apply to sorbent trap 

monitoring systems. 

5.2.2.2 The same RATA performance 

criteria specified in Table A–4 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 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 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 


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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 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 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 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. 

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 × 10¥11 to convert it from mg/ 

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 part 75 of this chapter, 

provided that the diluent gas monitor is not 

out-of-control and the hourly average O2

concentration is above 14.0% O2 (19.0% for 

an IGCC) or the hourly average CO2

concentration is below 5.0% CO2 (1.0% for 

an IGCC), as applicable. 

6.2.1.3 Multiply the lb/MMBtu value 

obtained in section 6.2.1.2 of this appendix 

by 106 to convert it to lb/TBtu. 

6.2.1.4 The heat input-based Hg emission 

rate limit in Table 2 to this subpart must be 

met on a 30 boiler operating day rolling 

average basis. Use Equation 19–19 in EPA 

Method 19 to calculate the Hg emission rate 

for each averaging period. The term Ehj in 

Equation 19–19 must be in the units of the 

applicable emission limit. Do not include 

non-operating hours with zero emissions in 

the average. 

6.2.2 Electrical Output-Based Hg 

Emission Rates. Calculate electrical outputbased 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: 

Where: 

Mh = Hg mass emission rate for the hour (lb/ 

h) 

K = Units conversion constant, 6.24 × 10¥11

lb-scm/mg-scf, 

Ch = Hourly average Hg concentration, wet 

basis (mg/scm) 

Qh = Stack gas volumetric flow rate for the 

hour (scfh). 

(Note: Use unadjusted flow rate values; 

bias adjustment is not required) 

Where: Mh = Hg mass emission rate for the hour (lb/ 

h) 

K = Units conversion constant, 6.24 x 10¥11

lb-scm/mg-scf. 


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Ch = Hourly average Hg concentration, dry 

basis (mg/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. 

Where: 

Eho = Electrical output-based Hg emission 

rate (lb/GWh). 

Mh = Hg mass emission rate for the hour, 

from Equation A–2 or A–3 of this 

section, as applicable (lb/h). 

(MW)h = Gross electrical load for the hour, 

in megawatts (MW). 

10 3 = Conversion factor from megawatts to 

gigawatts. 

6.2.2.3 The applicable electrical outputbased Hg emission rate limit in Table 1 or 2 

to this subpart must be met on a 30-boiler 

operating day rolling average basis. Use 

Equation A–5 of this section to calculate the 

Hg emission rate for each averaging period. 

Where: 

E ̄ o = Hg emission rate for the averaging 

period (lb/GWh). 

Eho = 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. 

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 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 

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 quality-assured value of Hg concentration 

for the hour; 

7.1.3.3 The hourly Hg concentration, if a 

quality-assured value is obtained for the hour 

(mg/scm, rounded to three significant figures); 

7.1.3.4 A special code, indicating 

whether or not a quality-assured 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 


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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 

(mg/scm, rounded to three significant figures). 

Note that when a quality-assured Hg 

concentration value is obtained for a 

particular data collection period, that single 

concentration value is applied to each 

operating hour of the data collection period. 

7.1.4.4 A special code, indicating 

whether or not a quality-assured 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 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. 

7.1.6.2 If hourly moisture corrections are 

required, either use a fuel-specific default 

moisture percentage from § 75.11(b)(1) of this 

chapter or a certified moisture monitoring 

system that meets the requirements of part 75 

of this chapter, to record the required data. 

If you use a moisture monitoring system, you 

must keep hourly records of the stack gas 

moisture content, as specified in § 75.57(c)(3) 

of this chapter. 

7.1.7 Records of Diluent Gas (CO2 or O2) 

Concentration. 

7.1.7.1 When a heat input-based Hg mass 

emissions limit must be met, in units of lb/ 

TBtu, hourly measurements of CO2 or O2

concentration are required to convert Hg 

concentrations to units of the standard. 

7.1.7.2 If hourly measurements of diluent 

gas concentration are needed, use a certified 

CO2 or O2 monitor that meets the 

requirements of part 75 of this chapter to 

record the required data. You must keep 

hourly CO2 or O2 concentration records, as 

specified in § 75.57(g) of this chapter. 

7.1.8 Hg Emission Rate Records. For 

applicable Hg emission limits in units of 

lb/TBtu or lb/GWh, record the following 

information for each affected unit or common 

stack: 

7.1.8.1 The date and hour; 

7.1.8.2 The hourly Hg emissions rate 

(lb/TBtu or lb/GWh, as applicable, calculated 

according to section 6.2.1 or 6.2.2 of this 

appendix, rounded to three significant 

figures), if valid values of Hg concentration 

and all other required parameters (stack gas 

volumetric flow rate, diluent gas 

concentration, electrical load, and moisture 

data, as applicable) are obtained for the hour; 

7.1.8.3 An identification code for the 

formula (either the selected equation from 

Method 19 in section 6.2.1 of this appendix 

or Equation A–4 in section 6.2.2 of this 

appendix) used to derive the hourly Hg 

emission rate from Hg concentration, flow 

rate, electrical load, diluent gas 

concentration, and moisture data (as 

applicable); and 

7.1.8.4 A code indicating that the Hg 

emission rate was not calculated for the hour, 

if valid data for Hg concentration and/or any 

of the other necessary parameters are not 

obtained for the hour. For the purposes of 

this appendix, the substitute data values 

required under part 75 of this chapter for 

diluent gas concentration, stack gas flow rate 

and moisture content are not considered to 

be valid data. 

7.1.9 Certification and Quality Assurance 

Test Records. For any Hg CEMS and sorbent 

trap monitoring systems used to provide data 

under this subpart, record the following 

certification and quality-assurance 

information: 

7.1.9.1 The reference values, monitor 

responses, and calculated calibration error 

(CE) values, and a flag to indicate whether 

the test was done using elemental or oxidized 

Hg, for all required 7-day calibration error 

tests and daily calibration error tests of the 

Hg CEMS; 

7.1.9.2 The reference values, monitor 

responses, and calculated linearity error (LE) 

or system integrity error (SIE) values for all 

linearity checks of the Hg CEMS, and for all 

single-level and 3-level system integrity 

checks of the Hg CEMS; 

7.1.9.3 The CEMS and reference method 

readings for each test run and the calculated 

relative accuracy results for all RATAs of the 

Hg CEMS and/or sorbent trap monitoring 

systems; 

7.1.9.4 The stable stack gas and 

calibration gas readings and the calculated 

results for the upscale and downscale stages 

of all required cycle time tests of the Hg 

CEMS or, for a batch sampling Hg CEMS, the 

interval between measured Hg concentration 

readings; 

7.1.9.5 Supporting information for all 

required RATAs of the Hg monitoring 

systems, including records of the test dates, 

the raw reference method and monitoring 

system data, the results of sample analyses to 

substantiate the reported test results, and 

records of sampling equipment calibrations; 

7.1.9.6 For sorbent trap monitoring 

systems, also keep records of the results of 

all analyses of the sorbent traps used for 

routine daily operation of the system, and 

information documenting the results of all 

leak checks and the other applicable quality 

control procedures described in Table 12B– 

1 of Performance Specification (PS) 12B in 

appendix B to part 60 of this chapter. 

7.1.9.7 For stack gas flow rate, diluent 

gas, and (if applicable) moisture monitoring 

systems, you must keep records of all 

certification, recertification, diagnostic, and 

on-going quality-assurance tests of these 

systems, as specified in § 75.59 of this 

chapter. 

7.2 Reporting Requirements. 

7.2.1 General Reporting Provisions. The 

owner or operator shall comply with the 

following requirements for reporting Hg 

emissions from each affected unit (or group 

of units monitored at a common stack) under 

this subpart: 

7.2.1.1 Notifications, in accordance with 

paragraph 7.2.2 of this section; 

7.2.1.2 Monitoring plan reporting, in 

accordance with paragraph 7.2.3 of this 

section; 

7.2.1.3 Certification, recertification, and 

QA test submittals, in accordance with 

paragraph 7.2.4 of this section; and 

7.2.1.4 Electronic quarterly report 

submittals, in accordance with paragraph 

7.2.5 of this section. 

7.2.2 Notifications. The owner or operator 

shall provide notifications for each affected 

unit (or group of units monitored at a 

common stack) under this subpart in 

accordance with § 63.10030. 

7.2.3 Monitoring Plan Reporting. For each 

affected unit (or group of units monitored at 

a common stack) under this subpart using Hg 

CEMS or sorbent trap monitoring system to 

measure Hg emissions, the owner or operator 

shall make electronic and hard copy 

monitoring plan submittals as follows: 

7.2.3.1 Submit the electronic and hard 

copy information in section 7.1.1.2 of this 

appendix pertaining to the Hg monitoring 

systems at least 21 days prior to the 

applicable date in § 63.9984. Also submit the 

monitoring plan information in § 75.53.(g) 

pertaining to the flow rate, diluent gas, and 

moisture monitoring systems within that 

same time frame, if the required records are 

not already in place. 

7.2.3.2 Whenever an update of the 

monitoring plan is required, as provided in 

paragraph 7.1.1.1 of this section. An 

electronic monitoring plan information 


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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 kept on record according to section 

7.1 of this appendix. 

7.2.4 Certification, Recertification, and 

Quality-Assurance Test Reporting. Except for 

daily QA tests of the required monitoring 

systems (i.e., calibration error tests and flow 

monitor interference checks), the results of 

all required certification, recertification, and 

quality-assurance tests described in 

paragraphs 7.1.10.1 through 7.1.10.7 of this 

section (except for test results previously 

submitted, e.g., under the ARP) shall be 

submitted electronically, using the ECMPS 

Client Tool, either prior to or concurrent with 

the relevant quarterly electronic emissions 

report. 

7.2.5 Quarterly Reports. 

7.2.5.1 Beginning with the report for the 

calendar quarter in which the initial 

compliance demonstration is completed or 

the calendar quarter containing the 

applicable date in § 63.9984, the owner or 

operator of any affected unit shall use the 

ECMPS Client Tool to submit electronic 

quarterly reports to the Administrator, in an 

XML format specified by the Administrator, 

for each affected unit (or group of units 

monitored at a common stack) under this 

subpart. 

7.2.5.2 The electronic reports must be 

submitted within 30 days following the end 

of each calendar quarter, except for units that 

have been placed in long-term cold storage. 

7.2.5.3 Each electronic quarterly report 

shall include the following information: 

7.2.5.3.1 The date of report generation; 

7.2.5.3.2 Facility identification 

information; 

7.2.5.3.3 The information in paragraphs 

7.1.2 through 7.1.8 of this section, as 

applicable to the Hg emission measurement 

methodology (or methodologies) used and 

the units of the Hg emission standard(s); and 

7.2.5.3.4 The results of all daily 

calibration error tests of the Hg CEMS, as 

described in paragraph 7.1.90.1 of this 

section and (if applicable) the results of all 

daily flow monitor interference checks. 

7.2.5.4 Compliance Certification. Based 

on reasonable inquiry of those persons with 

primary responsibility for ensuring that all 

Hg emissions from the affected unit(s) under 

this subpart have been correctly and fully 

monitored, the owner or operator shall 

submit a compliance certification in support 

of each electronic quarterly emissions 

monitoring report. The compliance 

certification shall include a statement by a 

responsible official with that official’s name, 

title, and signature, certifying that, to the best 

of his or her knowledge, the report is true, 

accurate, and complete. 

Appendix B to Subpart UUUUU—-HCl 

and HF Monitoring Provisions 

1. Applicability 

These monitoring provisions apply to the 

measurement of HCl and/or HF emissions 

from electric utility steam generating units, 

using CEMS. The CEMS must be capable of 

measuring HCl and/or HF in the appropriate 

units of the applicable emissions standard 

(e.g., lb/MMBtu, lb/MWh, or lb/GWh). 

2. Monitoring of HCl and/or HF Emissions 

2.1 Monitoring System Installation 

Requirements. Install HCl and/or HF CEMS 

and any additional monitoring systems 

needed to convert pollutant concentrations to 

units of the applicable emissions limit in 

accordance with Performance Specification 

15 for extractive Fourier Transform Infrared 

Spectroscopy (FTIR) continuous emissions 

monitoring systems in appendix B to part 60 

of this chapter and § 63.10010(a). 

2.2 Primary and Backup Monitoring 

Systems. The provisions pertaining to 

primary and redundant backup monitoring 

systems in section 2.2 of appendix A to this 

subpart apply to HCl and HF CEMS and any 

additional monitoring systems needed to 

convert pollutant concentrations to units of 

the applicable emissions limit. 

2.3 FTIR Monitoring System Equipment, 

Supplies, Definitions, and General 

Operation. The provisions of Performance 

Specification 15 Sections 2.0, 3.0, 4.0, 5.0, 

6.0, and 10.0 apply. 

3. Initial Certification Procedures 

The initial certification procedures for the 

HCl or HF CEMS used to provide data under 

this subpart are as follows: 

3.1 The HCl and/or HF CEMS must be 

certified according to Performance 

Specification 15 using the procedures for gas 

auditing and comparison to a reference 

method (RM) as specified in sections 3.1.1 

and 3.1.2 below. (Please Note: EPA plans to 

publish a technology neutral performance 

specification and appropriate on-going 

quality-assurance requirements for HCl 

CEMS in the near future along with 

amendments to this appendix to 

accommodate their use.) 

3.1.1 You must conduct a gas audit of the 

HCl and/or HF CEMS as described in section 

9.1 of Performance Specification 15, with the 

exceptions listed in sections 3.1.2.1 and 

3.1.2.2 below. 

3.1.1.1 The audit sample gas does not 

have to be obtained from the Administrator; 

however, it must be (1) from a secondary 

source of certified gases (i.e., independent of 

any calibration gas used for the daily 

calibration assessments) and (2) directly 

traceable to National Institute of Standards 

and Technology (NIST) or VSL Dutch 

Metrology Institute (VSL) reference materials 

through an unbroken chain of comparisons. 

If audit gas traceable to NIST or VSL 

reference materials is not available, you may 

use a gas with a concentration certified to a 

specified uncertainty by the gas 

manufacturer. 

3.1.1.2 Analyze the results of the gas 

audit using the calculations in section 12.1 

of Performance Specification 15. The 

calculated correction factor (CF) from Eq. 6 

of Performance Specification 15 must be 

between 0.85 and 1.15. You do not have to 

test the bias for statistical significance. 

3.1.2 You must perform a relative 

accuracy test audit or RATA according to 

section 11.1.1.4 of Performance Specification 

15 and the requirements below. Perform the 

RATA of the HCl or HF CEMS at normal 

load. Acceptable HCl/HF reference methods 

(RM) are Methods 26 and 26A in appendix 

A–8 to part 60 of this chapter, Method 320 

in Appendix A to this part, or ASTM D6348– 

03 (Reapproved 2010) ‘‘Standard Test 

Method for Determination of Gaseous 

Compounds by Extractive Direct Interface 

Fourier Transform Infrared (FTIR) 

Spectroscopy’’ (incorporated by reference, 

see § 63.14), each applied based on the 

criteria set forth in Table 5 of this subpart. 

3.1.2.1 When ASTM D6348–03 is used as 

the RM, the following conditions must be 

met: 

3.1.2.1.1 The test plan preparation and 

implementation in the Annexes to ASTM 

D6348–03, Sections A1 through A8 are 

mandatory; 

3.1.2.1.2 In ASTM D6348–03 Annex A5 

(Analyte Spiking Technique), the percent (%) 

R must be determined for each target analyte 

(see Equation A5.5); 

3.1.2.1.3 For the ASTM D6348–03 test 

data to be acceptable for a target analyte, %R 

must be 70% ≥ R ≤ 130%; and 

3.1.2.1.4 The %R value for each 

compound must be reported in the test report 

and all field measurements corrected with 

the calculated %R value for that compound 

using the following equation: 

3.1.2.2 The relative accuracy (RA) of the 

HCl or HF CEMS must be no greater than 20 

percent of the mean value of the RM test data 

in units of ppm on the same moisture basis. 

Alternatively, if the mean RM value is less 

than 1.0 ppm, the RA results are acceptable 

if the absolute value of the difference 

between the mean RM and CEMS values does 

not exceed 0.20 ppm. 

3.2 Any additional stack gas flow rate, 

diluent gas, and moisture monitoring 

system(s) needed to express pollutant 

concentrations in units of the applicable 

emissions limit must be certified according to 

part 75 of this chapter. 


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4. Recertification Procedures 

Whenever the owner or operator makes a 

replacement, modification, or change to a 

certified CEMS that may significantly affect 

the ability of the system to accurately 

measure or record pollutant or diluent gas 

concentrations, stack gas flow rates, or stack 

gas moisture content, the owner or operator 

shall recertify the monitoring system. 

Furthermore, whenever the owner or 

operator makes a replacement, modification, 

or change to the flue gas handling system or 

the unit operation that may significantly 

change the concentration or flow profile, the 

owner or operator shall recertify the 

monitoring system. The same tests performed 

for the initial certification of the monitoring 

system shall be repeated for recertification, 

unless otherwise specified by the 

Administrator. Examples of changes that 

require recertification include: Replacement 

of a gas analyzer; complete monitoring 

system replacement, and changing the 

location or orientation of the sampling probe. 

5. On-Going Quality Assurance 

Requirements 

5.1 For on-going QA test requirements for 

HCl and HF CEMS, implement the quality 

assurance/quality control procedures of 

Performance Specification 15 of appendix B 

to part 60 of this chapter as set forth in 

sections 5.1.1 through 5.1.3 and 5.3.2 of this 

appendix. 

5.1.1 On a daily basis, you must assess 

the calibration error of the HCl or HF CEMS 

using either a calibration transfer standard as 

specified in Performance Specification 15 

Section 10.1 which references Section 4.5 of 

the FTIR Protocol or a HCl and/or HF 

calibration gas at a concentration no greater 

than two times the level corresponding to the 

applicable emission limit. A calibration 

transfer standard is a substitute calibration 

compound chosen to ensure that the FTIR is 

performing well at the wavelength regions 

used for analysis of the target analytes. The 

measured concentration of the calibration 

transfer standard or HCl and/or HF 

calibration gas results must agree within ± 5 

percent of the reference gas value after 

correction for differences in pressure. 

5.1.2 On a quarterly basis, you must 

conduct a gas audit of the HCl and/or HF 

CEMS as described in section 3.1.1 of this 

appendix. For the purposes of this appendix, 

‘‘quarterly’’ means once every ‘‘QA operating 

quarter’’ (as defined in section 3.1.20 of 

appendix A to this subpart). You have the 

option to use HCl gas in lieu of HF gas for 

conducting this audit on an HF CEMS. To the 

extent practicable, perform consecutive 

quarterly gas audits at least 30 days apart. 

The initial quarterly audit is due in the first 

QA operating quarter following the calendar 

quarter in which certification testing of the 

CEMS is successfully completed. Up to three 

consecutive exemptions from the quarterly 

audit requirement are allowed for ‘‘non-QA 

operating quarters’’ (i.e., calendar quarters in 

which there are less than 168 unit or stack 

operating hours). However, no more than 

four consecutive calendar quarters may 

elapse without performing a gas audit, except 

as otherwise provided in section 5.3.3.2.1 of 

this appendix. 

5.1.3 You must perform an annual 

relative accuracy test audit or RATA of the 

HCl or HF CEMS as described in section 3.1.2 

of this appendix. Perform the RATA at 

normal load. For the purposes of this 

appendix, ‘‘annual’’ means once every four 

‘‘QA operating quarters’’ (as defined in 

section 3.1.20 of appendix A to this subpart). 

The first annual RATA is due within four QA 

operating quarters following the calendar 

quarter in which the initial certification 

testing of the HCl or HF CEMS is successfully 

completed. The provisions in section 5.1.2.4 

of appendix A to this subpart pertaining to 

RATA deadline extensions also apply. 

5.2 Stack gas flow rate, diluent gas, and 

moisture monitoring systems must meet the 

applicable on-going QA test requirements of 

part 75 of this chapter. 

5.3 Data Validation. 

5.3.1 Out-of-Control Periods. A HCl or HF 

CEMS that is used to provide data under this 

appendix is considered to be out-of-control, 

and data from the CEMS may not be reported 

as quality-assured, when any acceptance 

criteria for a required QA test is not met. The 

HCl or HF CEMS is also considered to be outof-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. Outof-control periods are counted as hours of 

monitoring system downtime. 

5.3.2 Grace Periods. For the purposes of 

this appendix, a ‘‘grace period’’ is defined as 

a specified number of unit or stack operating 

hours after the deadline for a required 

quality-assurance test of a continuous 

monitor has passed, in which the test may be 

performed and passed without loss of data. 

5.3.2.1 For the flow rate, diluent gas, and 

moisture monitoring systems described in 

section 5.2 of this appendix, a 168 unit or 

stack operating hour grace period is available 

for quarterly linearity checks, and a 720 unit 

or stack operating hour grace period is 

available for RATAs, as provided, 

respectively, in sections 2.2.4 and 2.3.3 of 

appendix B to part 75 of this chapter. 

5.3.2.2 For the purposes of this appendix, 

if the deadline for a required gas audit or 

RATA of a HCl or HF CEMS cannot be met 

due to circumstances beyond the control of 

the owner or operator: 

5.3.2.2.1 A 168 unit or stack operating 

hour grace period is available in which to 

perform the gas audit; or 

5.3.2.2.2 A 720 unit or stack operating 

hour grace period is available in which to 

perform the RATA. 

5.3.2.3 If a required QA test is performed 

during a grace period, the deadline for the 

next test shall be determined as follows: 

5.3.2.3.1 For a gas audit or RATA of the 

monitoring systems described in section 5.1 

of this appendix, determine the deadline for 

the next gas audit or RATA (as applicable) in 

accordance with section 2.2.4(b) or 2.3.3(d) of 

appendix B to part 75 of this chapter; treat 

a gas audit in the same manner as a linearity 

check. 

5.3.2.3.2 For the gas audit of a HCl or HF 

CEMS, the grace period test only satisfies the 

audit requirement for the calendar quarter in 

which the test was originally due. If the 

calendar quarter in which the grace period 

audit is performed is a QA operating quarter, 

an additional gas audit is required for that 

quarter. 

5.3.2.3.3 For the RATA of a HCl or HF 

CEMS, the next RATA is due within three 

QA operating quarters after the calendar 

quarter in which the grace period test is 

performed. 

5.3.4 Conditional Data Validation. For 

recertification and diagnostic testing of the 

monitoring systems that are used to provide 

data under this appendix, and for the 

required QA tests when non-redundant 

backup monitoring systems or temporary 

like-kind replacement analyzers are brought 

into service, the conditional data validation 

provisions in §§ 75.20(b)(3)(ii) through 

(b)(3)(ix) of this chapter may be used to avoid 

or minimize data loss. The allotted window 

of time to complete calibration tests and 

RATAs shall be as specified in 

§ 75.20(b)(3)(iv) of this chapter; the allotted 

window of time to complete a gas audit shall 

be the same as for a linearity check (i.e., 168 

unit or stack operating hours). 

6. Missing Data Requirements 

For the purposes of this appendix, the 

owner or operator of an affected unit shall 

not substitute for missing data from HCl or 

HF CEMS. Any process operating hour for 

which quality-assured HCl or HF 

concentration data are not obtained is 

counted as an hour of monitoring system 

downtime. 

7. Bias Adjustment 

Bias adjustment of hourly emissions data 

from a HCl or HF CEMS is not required. 

8. QA/QC Program Requirements 

The owner or operator shall develop and 

implement a quality assurance/quality 

control (QA/QC) program for the HCl and/or 

HF CEMS that are used to provide data under 

this subpart. At a minimum, the program 

shall include a written plan that describes in 

detail (or that refers to separate documents 

containing) complete, step-by-step 

procedures and operations for the most 

important QA/QC activities. Electronic 

storage of the QA/QC plan is permissible, 

provided that the information can be made 

available in hard copy to auditors and 

inspectors. The QA/QC program 

requirements for the other monitoring 

systems described in section 5.2 of this 

appendix are specified in section 1 of 

appendix B to part 75 of this chapter. 

8.1 General Requirements for HCl and HF 

CEMS. 

8.1.1 Preventive Maintenance. Keep a 

written record of procedures needed to 

maintain the HCl and/or HF CEMS in proper 

operating condition and a schedule for those 

procedures. This shall, at a minimum, 

include procedures specified by the 

manufacturers of the equipment and, if 

applicable, additional or alternate procedures 

developed for the equipment. 

8.1.2 Recordkeeping and Reporting. Keep 

a written record describing procedures that 

will be used to implement the recordkeeping 

and reporting requirements of this appendix. 

8.1.3 Maintenance Records. Keep a 

record of all testing, maintenance, or repair 


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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 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 

emissions limit. 

9.3.1 For heat input-based emission rates, 

select an appropriate emission rate equation 

from among Equations 19–1 through 19–9 in 

EPA Method 19 in appendix A–7 to part 60 

of this chapter, to calculate the HCl or HF 

emission rate in lb/MMBtu. Multiply the HCl 

concentration value (ppm) by 9.43 × 10¥8 to 

convert it to lb/scf, for use in the applicable 

Method 19 equation. For HF, the conversion 

constant from ppm to lb/scf is 5.18 × 10¥8. 

9.3.2 For electrical output-based emission 

rates, first calculate the HCl or HF mass 

emission rate (lb/h), using an equation that 

has the general form of Equation A–2 or A– 

3 in appendix A to this subpart (as 

applicable), replacing the value of K with 

9.43 × 10¥8 lb/scf-ppm (for HCl) or 5.18 × 

10¥8 (for HF) and defining Ch as the hourly 

average HCl or HF concentration in ppm. 

Then, use Equation A–4 in appendix A to 

this subpart to calculate the HCl or HF 

emission rate in lb/GWh. If the applicable 

HCl or HF limit is expressed in lb/MWh, 

divide the result from Equation A–4 by 103. 

9.4 Use Equation A–5 in appendix A of 

this subpart to calculate the required 30 

operating day rolling average HCl or HF 

emission rates. Round off each 30 operating 

day average to two significant figures. The 

term Eho in Equation A–5 must be in the units 

of the applicable emissions limit. 

10. Recordkeeping Requirements 

10.1 For each HCl or HF CEMS installed 

at an affected source, and for any other 

monitoring system(s) needed to convert 

pollutant concentrations to units of the 

applicable emissions limit, the owner or 

operator must maintain a file of all 

measurements, data, reports, and other 

information required by this appendix in a 

form suitable for inspection, for 5 years from 

the date of each record, in accordance with 

§ 63.10033. The file shall contain the 

information in paragraphs 10.1.1 through 

10.1.8 of this section. 

10.1.1 Monitoring Plan Records. For each 

affected unit or group of units monitored at 

a common stack, the owner or operator shall 

prepare and maintain a monitoring plan for 

the HCl and/or HF CEMS and any other 

monitoring system(s) (i.e, flow rate, diluent 

gas, or moisture systems) needed to convert 

pollutant concentrations to units of the 

applicable emission standard. The 

monitoring plan shall contain essential 

information on the continuous monitoring 

systems and shall explain how the data 

derived from these systems ensure that all 

HCl or HF emissions from the unit or stack 

are monitored and reported. 

10.1.1.1 Updates. Whenever the owner or 

operator makes a replacement, modification, 

or change in a certified continuous HCl or HF 

monitoring system that is used to provide 

data under this subpart (including a change 

in the automated data acquisition and 

handling system or the flue gas handling 

system) which affects information reported in 

the monitoring plan (e.g., a change to a serial 

number for a component of a monitoring 

system), the owner or operator shall update 

the monitoring plan. 

10.1.1.2 Contents of the Monitoring Plan. 

For HCl and/or HF CEMS, the monitoring 

plan shall contain the applicable electronic 

and hard copy information in sections 

10.1.1.2.1 and 10.1.1.2.2 of this appendix. 

For stack gas flow rate, diluent gas, and 

moisture monitoring systems, the monitoring 

plan shall include the electronic and hard 

copy information required for those systems 

under § 75.53 (g) of this chapter. The 

electronic monitoring plan shall be evaluated 

using the ECMPS Client Tool. 

10.1.1.2.1 Electronic. Record the unit or 

stack ID number(s); monitoring location(s); 

the HCl or HF monitoring methodology used 

(i.e., CEMS); HCl or HF monitoring system 

information, including, but not limited to: 

unique system and component ID numbers; 

the make, model, and serial number of the 

monitoring equipment; the sample 

acquisition method; formulas used to 

calculate emissions; monitor span and range 

information (if applicable). 

10.1.1.2.2 Hard Copy. Keep records of the 

following: schematics and/or blueprints 

showing the location of the monitoring 

system(s) and test ports; data flow diagrams; 

test protocols; monitor span and range 

calculations (if applicable); miscellaneous 

technical justifications. 

10.1.2 Operating Parameter Records. For 

the purposes of this appendix, the owner or 

operator shall record the following 

information for each operating hour of each 

affected unit or group of units utilizing a 

common stack, to the extent that these data 

are needed to convert pollutant concentration 

data to the units of the emission standard. 

For non-operating hours, record only the 

items in paragraphs 10.1.2.1 and 10.1.2.2 of 

this section. If there is heat input to the 

unit(s), but no electrical load, record only the 

items in paragraphs 10.1.2.1, 10.1.2.2, and (if 

applicable) 10.1.2.4 of this section. 

10.1.2.1 The date and hour; 

10.1.2.2 The unit or stack operating time 

(rounded up to the nearest fraction of an hour 

(in equal increments that can range from one 

hundredth to one quarter of an hour, at the 

option of the owner or operator); 

10.1.2.3 The hourly gross unit load 

(rounded to nearest MWge); and 

10.1.2.4 If applicable, the F-factor used to 

calculate the heat input-based pollutant 

emission rate. 

10.1.3 HCl and/or HF Emissions Records. 

For HCl and/or HF CEMS, the owner or 

operator must record the following 

information for each unit or stack operating 

hour: 

10.1.3.1 The date and hour; 

10.1.3.2 Monitoring system and 

component identification codes, as provided 

in the electronic monitoring plan, for each 

hour in which the CEMS provides a qualityassured value of HCl or HF concentration (as 

applicable); 

10.1.3.3 The pollutant concentration, for 

each hour in which a quality-assured value 

is obtained. For HCl and HF, record the data 

in parts per million (ppm), rounded to three 

significant figures. 

10.1.3.4 A special code, indicating 

whether or not a quality-assured 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 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 outputbased 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. 


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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 noncoal-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 

chapter. 

10.1.6 Records of Diluent Gas (CO2 or O2) 

Concentration. 

10.1.6.1 To assess compliance with a heat 

input-based HCl or HF emission rate limit in 

units of lb/MMBtu, hourly measurements of 

CO2 or O2 concentration are required to 

convert pollutant concentrations to units of 

the standard. 

10.1.6.2 If hourly measurements of 

diluent gas concentration are needed, you 

must use a certified CO2 or O2 monitor that 

meets the requirements of part 75 of this 

chapter to record the required data. For all 

diluent gas monitors, you must keep hourly 

CO2 or O2 concentration records, as specified 

in § 75.57(g) of this chapter. 

10.1.7 HCl and HF Emission Rate 

Records. For applicable HCl and HF emission 

limits in units of lb/MMBtu, lb/MWh, or lb/ 

GWh, record the following information for 

each affected unit or common stack: 

10.1.7.1 The date and hour; 

10.1.7.2 The hourly HCl and/or HF 

emissions rate (lb/MMBtu, lb/MWh, or lb/ 

GWh, as applicable, rounded to three 

significant figures), for each hour in which 

valid values of HCl or HF concentration and 

all other required parameters (stack gas 

volumetric flow rate, diluent gas 

concentration, electrical load, and moisture 

data, as applicable) are obtained for the hour; 

10.1.7.3 An identification code for the 

formula used to derive the hourly HCl or HF 

emission rate from HCl or HF concentration, 

flow rate, electrical load, diluent gas 

concentration, and moisture data (as 

applicable); and 

10.1.7.4 A code indicating that the HCl or 

HF emission rate was not calculated for the 

hour, if valid data for HCl or HF 

concentration and/or any of the other 

necessary parameters are not obtained for the 

hour. For the purposes of this appendix, the 

substitute data values required under part 75 

of this chapter for diluent gas concentration, 

stack gas flow rate and moisture content are 

not considered to be valid data. 

10.1.8 Certification and Quality 

Assurance Test Records. For the HCl and/or 

HF CEMS used to provide data under this 

subpart at each affected unit (or group of 

units monitored at a common stack), record 

the following information for all required 

certification, recertification, diagnostic, and 

quality-assurance tests: 

10.1.8.1 HCl and HF CEMS. 

10.1.8.1.1 For all required daily 

calibrations (including calibration transfer 

standard tests) of the HCl or HF CEMS, 

record the test dates and times, reference 

values, monitor responses, and calculated 

calibration error values; 

10.1.8.1.2 For gas audits of HCl or HF 

CEMS, record the date and time of each 

spiked and unspiked sample, the audit gas 

reference values and uncertainties. Keep 

records of all calculations and data analyses 

required under sections 9.1 and 12.1 of 

Performance Specification 15, and the results 

of those calculations and analyses. 

10.1.8.1.3 For each RATA of a HCl or HF 

CEMS, record the date and time of each test 

run, the reference method(s) used, and the 

reference method and HCl or HF CEMS 

values. Keep records of the data analyses and 

calculations used to determine the relative 

accuracy. 

10.1.8.2 Additional Monitoring Systems. 

For the stack gas flow rate, diluent gas, and 

moisture monitoring systems described in 

section 3.2 of this appendix, you must keep 

records of all certification, recertification, 

diagnostic, and on-going quality-assurance 

tests of these systems, as specified in 

§ 75.59(a) of this chapter. 

11. Reporting Requirements 

11.1 General Reporting Provisions. The 

owner or operator shall comply with the 

following requirements for reporting HCl 

and/or HF emissions from each affected unit 

(or group of units monitored at a common 

stack): 

11.1.1 Notifications, in accordance with 

paragraph 11.2 of this section; 

11.1.2 Monitoring plan reporting, in 

accordance with paragraph 11.3 of this 

section; 

11.1.3 Certification, recertification, and 

QA test submittals, in accordance with 

paragraph 11.4 of this section; and 

11.1.4 Electronic quarterly report 

submittals, in accordance with paragraph 

11.5 of this section. 

11.2 Notifications. The owner or operator 

shall provide notifications for each affected 

unit (or group of units monitored at a 

common stack) in accordance with 

§ 63.10030. 

11.3 Monitoring Plan Reporting. For each 

affected unit (or group of units monitored at 

a common stack) using HCl and/or HF CEMS, 

the owner or operator shall make electronic 

and hard copy monitoring plan submittals as 

follows: 

11.3.1 Submit the electronic and hard 

copy information in section 10.1.1.2 of this 

appendix pertaining to the HCl and/or HF 

monitoring systems at least 21 days prior to 

the applicable date in § 63.9984. Also, if 

applicable, submit monitoring plan 

information pertaining to any required flow 

rate, diluent gas, and/or moisture monitoring 

systems within that same time frame, if the 

required records are not already in place. 

11.3.2 Update the monitoring plan when 

required, as provided in paragraph 10.1.1.1 of 

this appendix. An electronic monitoring plan 

information update must be submitted either 

prior to or concurrent with the quarterly 

report for the calendar quarter in which the 

update is required. 

11.3.3 All electronic monitoring plan 

submittals and updates shall be made to the 

Administrator using the ECMPS Client Tool. 

Hard copy portions of the monitoring plan 

shall be kept on record according to section 

10.1 of this appendix. 

11.4 Certification, Recertification, and 

Quality-Assurance Test Reporting 

Requirements. Except for daily QA tests (i.e., 

calibrations and flow monitor interference 

checks), which are included in each 

electronic quarterly emissions report, use the 

ECMPS Client Tool to submit the results of 

all required certification, recertification, 

quality-assurance, and diagnostic tests of the 

monitoring systems required under this 

appendix electronically, either prior to or 

concurrent with the relevant quarterly 

electronic emissions report. 

11.4.1 For daily calibrations (including 

calibration transfer standard tests), report the 

information in § 75.59(a)(1) of this chapter, 

excluding paragraphs (a)(1)(ix) through 

(a)(1)(xi). 

11.4.2 For each quarterly gas audit of a 

HCl or HF CEMS, report: 

11.4.2.1 Facility ID information; 

11.4.2.2 Monitoring system ID number; 

11.4.2.3 Type of test (e.g., quarterly gas 

audit); 

11.4.2.4 Reason for test; 

11.4.2.5 Certified audit (spike) gas 

concentration value (ppm); 

11.4.2.6 Measured value of audit (spike) 

gas, including date and time of injection; 

11.4.2.7 Calculated dilution ratio for 

audit (spike) gas; 

11.4.2.8 Date and time of each spiked flue 

gas sample; 

11.4.2.9 Date and time of each unspiked 

flue gas sample; 

11.4.2.10 The measured values for each 

spiked gas and unspiked flue gas sample 

(ppm); 

11.4.2.11 The mean values of the spiked 

and unspiked sample concentrations and the 

expected value of the spiked concentration as 

specified in section 12.1 of Performance 

Specification 15 (ppm); 

11.4.2.12 Bias at the spike level as 

calculated using equation 3 in section 12.1 of 

Performance Specification 15; and 

11.4.2.13 The correction factor (CF), 

calculated using equation 6 in section 12.1 of 

Performance Specification 15. 

11.4.3 For each RATA of a HCl or HF 

CEMS, report: 

11.4.3.1 Facility ID information; 

11.4.3.2 Monitoring system ID number; 

11.4.3.3 Type of test (i.e., initial or annual 

RATA); 

11.4.3.4 Reason for test; 

11.4.3.5 The reference method used; 

11.4.3.6 Starting and ending date and 

time for each test run; 

11.4.3.7 Units of measure; 

11.4.3.8 The measured reference method 

and CEMS values for each test run, on a 

consistent moisture basis, in appropriate 

units of measure; 

11.4.3.9 Flags to indicate which test runs 

were used in the calculations; 

11.4.3.10 Arithmetic mean of the CEMS 

values, of the reference method values, and 

of their differences; 

11.4.3.11 Standard deviation, as specified 

in Equation 2–4 of Performance Specification 

2 in appendix B to part 60 of this chapter; 

11.4.3.12 Confidence coefficient, as 

specified in Equation 2–5 of Performance 

Specification 2 in appendix B to part 60 of 

this chapter; and 


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11.4.3.13 Relative accuracy calculated 

using Equation 2–6 of Performance 

Specification 2 in appendix B to part 60 of 

this chapter or, if applicable, according to the 

alternative procedure for low emitters 

described in section 3.1.2.2 of this appendix. 

If applicable use a flag to indicate that the 

alternative RA specification for low emitters 

has been applied. 

11.4.4 Reporting Requirements for 

Diluent Gas, Flow Rate, and Moisture 

Monitoring Systems. For the certification, 

recertification, diagnostic, and QA tests of 

stack gas flow rate, moisture, and diluent gas 

monitoring systems that are certified and 

quality-assured according to part 75 of this 

chapter, report the information in section 

10.1.9.3 of this appendix. 

11.5 Quarterly Reports. 

11.5.1 Beginning with the report for the 

calendar quarter in which the initial 

compliance demonstration is completed or 

the calendar quarter containing the 

applicable date in § 63.10005(g), (h), or (j) 

(whichever is earlier), the owner or operator 

of any affected unit shall use the ECMPS 

Client Tool to submit electronic quarterly 

reports to the Administrator, in an XML 

format specified by the Administrator, for 

each affected unit (or group of units 

monitored at a common stack). 

11.5.2 The electronic reports must be 

submitted within 30 days following the end 

of each calendar quarter, except for units that 

have been placed in long-term cold storage. 

11.5.3 Each electronic quarterly report 

shall include the following information: 

11.5.3.1 The date of report generation; 

11.5.3.2 Facility identification 

information; 

11.5.3.3 The information in sections 

10.1.2 through 10.1.7 of this appendix, as 

applicable to the type(s) of monitoring 

system(s) used to measure the pollutant 

concentrations and other necessary 

parameters. 

11.5.3.4 The results of all daily 

calibrations (including calibration transfer 

standard tests) of the HCl or HF monitor as 

described in section 10.1.8.1.1 of this 

appendix; and 

11.5.3.5 If applicable, the results of all 

daily flow monitor interference checks, in 

accordance with section 10.1.8.2 of this 

appendix. 

11.5.4 Compliance Certification. Based 

on reasonable inquiry of those persons with 

primary responsibility for ensuring that all 

HCl and/or HF emissions from the affected 

unit(s) have been correctly and fully 

monitored, the owner or operator shall 

submit a compliance certification in support 

of each electronic quarterly emissions 

monitoring report. The compliance 

certification shall include a statement by a 

responsible official with that official’s name, 

title, and signature, certifying that, to the best 

of his or her knowledge, the report is true, 

accurate, and complete. 

[FR Doc. 2012–806 Filed 2–15–12; 8:45 am] 

BILLING CODE 6560–50–P 


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